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National Fuel Gas Company Earnings Slides - Nov 2016

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Marcellus Drilling News
Marcellus Drilling News

The earnings PowerPoint slide deck used during an earnings call for NFG to highlight their fourth quarter and full year performance. NFG includes Seneca Resources (drilling subsidiary) and Empire Pipeline (midstream subsidiary).

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1 Investor Presentation Q4 Fiscal 2016 Update November 3, 2016
2 Safe Harbor For Forward Looking Statements This presentation may contain “forward-looking statements” as defined by the Private Securities Litigation Reform Act of 1995, including statements regarding future prospects, plans, objectives, goals, projections, estimates of oil and gas quantities, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new accounting rules, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions. Forward-looking statements involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, but there can be no assurance that management’s expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the forward-looking statements: Delays or changes in costs or plans with respect to Company projects or related projects of other companies, including difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators; governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which address, among other things, target rates of return, rate design and retained natural gas), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal; impairments under the SEC’s full cost ceiling test for natural gas and oil reserves; changes in the price of natural gas or oil; financial and economic conditions, including the availability of credit, and occurrences affecting the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions; factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas and oil reserves, including among others geology, lease availability, title disputes, weather conditions, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations; changes in laws, regulations or judicial interpretations to which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, real property, and exploration and production activities such as hydraulic fracturing; changes in price differentials between similar quantities of natural gas or oil at different geographic locations, and the effect of such changes on commodity production, revenues and demand for pipeline transportation capacity to or from such locations; other changes in price differentials between similar quantities of natural gas or oil having different quality, heating value, hydrocarbon mix or delivery date; the cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company; uncertainty of oil and gas reserve estimates; significant differences between the Company’s projected and actual production levels for natural gas or oil; changes in demographic patterns and weather conditions; changes in the availability, price or accounting treatment of derivative financial instruments; changes in economic conditions, including global, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services; the creditworthiness or performance of the Company’s key suppliers, customers and counterparties; economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities, acts of war, cyber attacks or pest infestation; significant differences between the Company’s projected and actual capital expenditures and operating expenses; changes in laws, actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company’s pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities; increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; or Increasing costs of insurance, changes in coverage and the ability to obtain insurance. Forward-looking statements include estimates of oil and gas quantities. Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible under existing economic conditions, operating methods and government regulations. Other estimates of oil and gas quantities, including estimates of probable reserves, possible reserves, and resource potential, are by their nature more speculative than estimates of proved reserves. Accordingly, estimates other than proved reserves are subject to substantially greater risk of being actually realized. Investors are urged to consider closely the disclosure in our Form 10-K available at www.nationalfuelgas.com. You can also obtain this form on the SEC’s website at www.sec.gov. For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements, see “Risk Factors” in the Company’s Form 10-K for the fiscal year ended September 30, 2015 and the Forms 10-Q for the quarters ended December 31, 2015, March 31, 2016 and June 30, 2016. The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence of unanticipated events.
3 Quality Assets - Exceptional Location - Unique Integration  1.8 Tcfe Proved Reserves (1)  785,000 net acres in Appalachia - mostly held in fee with no royalty  3 million Bbls per year of crude oil production in California  $278 million annual adjusted EBITDA (2)  $1.3+ billion midstream investments since 2010  Coordinated gathering and transmission infrastructure build-out with NFG Upstream  740,000 Utility customer accounts  Stable, regulated earnings & cash flows  Generates operational and financial synergies with other segments (1) Total proved reserves are as of September 30, 2016. See slide 35 for further discussion . (2) For the trailing twelve months ended September 30, 2016. A reconciliation of Adjusted EBITDA to Net Income as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation. Upstream Midstream Downstream
4 The National Fuel Value Proposition Unique Asset Mix and Integrated Model Provide Balance and Stability  Fee ownership on ~715,000 net acres in WDA = limited royalties or drilling commitments  Seneca has >900,000 Dth/day of firm transportation & sales contracts by end of fiscal 2018  Stacked pay potential in Utica and Geneseo shales across Marcellus acreage  Coordinated gathering & interstate pipeline infrastructure build-out with NFG midstream  Opportunity for further pipeline expansion to accommodate Appalachian supply growth Considerable Upstream and Midstream Growth Opportunities in Appalachia  Geographical and operational integration drives capital flexibility and reduces costs  Investment grade credit rating and liquidity to support long-term Appalachian growth strategy  Cash flow from rate-regulated businesses supports interest costs and funds the dividend Disciplined Approach To Capital Allocation and Returns on Investment  Capital allocation that is focused on earning economic returns  Strong hedge book helps insulate near-term earnings and cash flows from commodity volatility  Creating long-term, sustainable value remains our #1 shareholder priority
5 Adjusted EBITDA by Segment ($ millions) Balanced Earnings and Cash Flows $160 $172 $165 $164 $149 $137 $161 $186 $188 $199 $64 $69 $79 $397 $492 $539 $422 $364 $704 $852 $953 $843 $789 $0 $500 $1,000 $1,500 2012 2013 2014 2015 2016 Fiscal Year Exploration & Production Segment Gathering Segment Pipeline & Storage Segment Utility Segment Energy Marketing & Other Note: A reconciliation of Adjusted EBITDA to Net Income as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation. (1)
6 Flexibility to Responsibly Deploy Capital $58 $72 $89 $94 $98 $90 - $100 $144 $56 $140 $230 $114 $390 - $440 $80 $55 $138 $118 $54 $65 - $75 $694 $533 $603 $557 $99 $180 - $220 $977 $717 $970 $1,001 $366 $725-$835 $0 $500 $1,000 $1,500 2012 2013 2014 2015 2016 2017E Fiscal Year Exploration & Production Segment Gathering Segment Pipeline & Storage Segment Utility Segment Energy Marketing & Other (1) (1) FY 2016 actual capital expenditures reflects the netting of $157 million of up-front proceeds received from joint development partner for working interest in joint development wells. FY 2017 guidance also reflects the netting of anticipated proceeds received from the joint development partner. Note: A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. Capital Expenditures by Segment ($ millions) E&P Total NFG Gross CapEx $256 $523 JDA Proceeds ($157) ($157) Net CapEx $99 $366 CapEx Reconciliation for JDA Proceeds ($millions)
7 Strong Balance Sheet & Liquidity Total Equity 42% Total Debt 58% $3.6 Billion Total Capitalization as of September 30, 2016 1.89 x 1.89 x 1.77 x 2.27 x 2.66 x 2012 2013 2014 2015 2016 Fiscal Year End Debt/Adjusted EBITDA Capitalization Debt Maturity Profile ($MM) Liquidity Committed Credit Facilities Short-term Debt Outstanding Available Short-term Credit Facilities Cash Balance at 09/30/16 Total Liquidity at 09/30/16 $ 1,250 MM $ 0 MM $ 1,250 MM $ 130 MM $ 1,380 MM $300 $250 $500 $549 $500 $0 $200 $400 $600 Note: A reconciliation of Adjusted EBITDA to Net Income is included at the end of this presentation.
8 Dividend Track Record $0.00 $0.50 $1.00 $1.50 $2.00 Annual Rate at Fiscal Year End Annual Dividend Rate ($ /share) Consecutive Payments 114 Years Consecutive Increases 46 Years Current Dividend Rate $1.62 per Share Current Dividend Yield (1) 3.1% (1) As of November 2, 2016. NFG’s Dividend Consistency
9  Gathering: Just-in-time installation of gathering pipelines and compression facilities to accommodate Seneca growth  Pipeline & Storage: Construction of Northern Access (Nov. 17 in-service)  $455 million project (~$300mm to be spent in FY17)  Remain on track to receive regulatory approvals FY 2017 Capital Budget and Operating Plan (1) FY 2016 actual capital expenditures reflects the netting of $157 million of up-front proceeds received from joint development partner for working interest in joint development wells. FY 2017 guidance also reflects the netting of anticipated proceeds received from the joint development partner. Note: A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. $98 $90 - $100 $114 $390 - $440 $54 $65 - $75 $99 $180 - $220 $366 $725 - $835 $0 $250 $500 $750 $1,000 FY 2016 FY 2017 Forecast Exploration & Production Segment Gathering Segment Pipeline & Storage Segment Utility Segment Energy Marketing & Other (1) Upstream Capital Expenditures by Segment ($MM) FY2017 Operating Plan Highlights  Appalachia: 1-rig program / daylight-only frac crew  Development pace designed to utilize ~680Mdth/d of new FT available by the end of FY18  Flexibility to accelerate D&C to grow into FT efficiently  California: $35- $45 million capex to keep production flat Midstream Downstream  Utility: Planning to accelerate pipeline replacement in NY from 90 miles to 110 miles per year
10 Appalachia Overview Exploration & Production ~ Gathering ~ Pipeline & Storage
11 Integrated Vision for Long-term Growth in Appalachia 200,000 “Tier 1” fee-held acres in Pa. 1,050 locations economic < $2.00/MMBtu with minimal lease expiration Just-in-time build-out of Clermont Gathering System limits stranded pipeline assets/capital Northern Access projects to transport 660 MDth/d of Seneca- operated WDA production by FY18 Exploration & Production Pipeline & Storage Gathering 1 2 3 1 2 Long-term, return-driven approach to developing vast Marcellus & Utica acreage position Connecting Our Production to Our Interstate Pipeline System Expanding Our Interstate Pipeline System to Reach Premium Markets 3
12 Significant Appalachian Acreage Position  153 wells able to produce 270 MMcf/d  Mostly leased (16-18% royalty) with no significant near-term lease expirations  50-60 remaining Marcellus locations economic under $1.60/Mcf  Additional Utica & Geneseo potential  Limited development drilling until firm transportation on Atlantic Sunrise is available in mid-2018 Eastern Development Area (EDA) EDA - 70,000 Acres Western Development Area (WDA) WDA - 715,000 Acres  139 wells able to produce 290 MMcf/d  Large inventory of high quality Marcellus acreage economic under $2.00/Mcf  Fee ownership – lack of royalty enhances economics  Highly contiguous nature drives cost and operational efficiencies  660 MDth/d firm transportation by FY18 Fee Acreage Lease Acreage Upstream
13 Marcellus Shale: Western Development Area WDA Tier 1 Acreage – 200,000 Acres WDA Tier 1 Marcellus Economics(1) WDA Highlights  Large drilling inventory of quality Marcellus dry gas o ~1,100 locations economic < $2.00/MMBtu realized  Fee acreage provides flexibility / enhances economics o No royalty on most acreage o No lease expirations or requirements to drill acreage  Highly contiguous position drives best in class Marcellus well costs o Multi-well pad drilling averaging 10 wells with 8,000 ft. laterals o Water management operations lowering water costs to under $1 /Bbl  NFG midstream infrastructure supporting growth o NFG Clermont gathering system o NFG Northern Access projects 660 MDth/d firm transport to Dawn (Canada) and Midwest and northeast US markets  Early Utica test results in CRV on trend with other Utica wells in NE Pa. o Will have 8 Utica test wells on-line by end of FY 2018 (1) Internal rate of return (IRR) is pre-tax and includes estimated well costs under the current well design and cost structure and projected firm transportation, gathering, LOE and other operating costs. Avg Avg $3.00 15% IRR Locations Lateral EUR NYMEX/Dawn Realized Remaining Length (ft) (Bcf) IRR% Price CRV 53 8,000 8.5-9.5 27% $1.82 Hemlock/Ridgway 631 8,800 8-9 29% $1.79 Other Tier 1 406 8,500 7-8 25% $1.91 Clermont/ Rich Valley Hemlock Ridgway 2 - 4 BCF/well 7- 9.5 BCF/well 4 - 6 BCF/well EUR Color Key Upstream
14 WDA Clermont / Rich Valley Development  117 wells able to produce ~280 MMcf/d  Dropped to 1 rig in March 2016 (down from 3 rigs at start of fiscal 2016)  Rig additions planned to meet firm transport / sales obligations  Developing 75 wells with joint development partner (IOG)  63 wells drilled  50 wells online / producing  Just-in-time gathering infrastructure build- out provides significant capital flexibility to adjust scheduling and pace of Seneca’s development program  Regional focus of development minimizes capital outlay and improves returns CRV Development Summary Upstream
15  Assets: 75 current and future Marcellus development wells in the Clermont/Rich Valley region of Seneca’s WDA.  Locations Developed Under Initial Obligation: 39 wells  Remaining Locations to be Developed: 36 wells  Partner Option: IOG has one-time option to participate in a 7-well pad to be completed before December 31, 2017  Economics: IOG participates as an 80% working interest owner until the IOG achieves a 15% IRR hurdle. Seneca retains a 7.5% royalty and remaining 20% working interest.  Natural Gas Marketing: IOG to receive same realized price before hedging as Seneca on production from the joint development wells, including firm sales and the cost of firm transportation. Seneca WDA Joint Development Agreement (1) Estimated reduction in capital expenditures from joint development agreement assumes current wells costs. Transaction Key Terms of the Agreement On June 13, 2016, Seneca announced the extension of asset-level joint development agreement with IOG CRV – Marcellus Capital, LLC, an affiliate of IOG Capital, LP, and funds managed by affiliates of Fortress Investment Group LLC, to jointly develop Marcellus Shale natural gas assets located in the Western Development Area. Strategic Rationale  Significantly reduces near-term upstream capital spending Initial 39 wells - $170 million(1) Remaining 36 wells - $155 million(1)  Validates quality of Seneca’s Tier 1 Marcellus WDA acreage  Seneca maintains activity levels to continue to drive Marcellus drilling and completion efficiencies  Solidifies NFG’s midstream growth strategy: Gathering - All production from JV wells will flow through NFG Midstream’s Clermont Gathering System Pipeline & Storage - Provides production growth that will utilize the 660 MDth/d of firm transportation capacity on NFG’s Northern Access pipeline expansion projects available starting Nov. 1, 2017  Strengthened balance sheet and makes Seneca cash flow positive in near-term Seneca IOG Working Interest 20% 80% Net Revenue Interest 26% 74% Upstream
16 Marcellus Shale: Eastern Development Area EDA Acreage – 70,000 AcresEDA Highlights Covington & DCNR Tract 595 (Tioga Co., Pa.) • Marcellus locations fully developed • 92 wells(1) with 80 MMcf/d productive capacity • 70-80 MDth/d firm sales in FY17 • Production flows into NFG Covington Gathering System • Opportunity for future Geneseo & Utica development DCNR Tract 100 & Gamble (Lycoming Co., Pa.) • 61 wells(1) with 190 MMcf/d productive capacity • 115-160 MDth/d firm sales in FY17 • Atlantic Sunrise capacity (190 MDth/d) in mid-2018 • 55 remaining Marcellus locations economic < $1.60 /Mcf • Production flows into NFG Trout Run Gathering System • Geneseo well 24 IP test: 14.1MMcf/d on 4,920’ lat • Geneseo to provide 100-120 additional locations DCNR Tract 007 (Tioga Co., Pa) • 1 Utica and 1 Marcellus exploration well • Utica well 24 IP test: 22.7 MMcf/d • Expected to be placed on-line in Nov. 2016 • Utica Resource potential = ~1 Tcf over 70 well locations 3 1 2 (1) One well included in the total for both Tract 595 and Tract 100 is drilled into and producing from the Geneseo Shale. 3 1 2 Upstream
17 Best in Class Marcellus Well Costs $248 $148 $109 $91 $67 $58 $0 $100 $200 $300 2012 2013 2014 2015 2016 2017E $275 $208 $174 $153 $120 $110 $0 $100 $200 $300 2012 2013 2014 2015 2016 2017E Seneca Average Marcellus Well Cost(1) vs. Appalachian Peers (2) $663 $743 $800 $855 $867 $877 $988 $500 $600 $700 $800 $900 $1,000 Seneca CRV Peer 1 Peer 2 Industry Average Peer 3 Peer 4 Peer 5 $/lateralfoot (1) Seneca CRV reflects a $5.3 million “all-in” total well cost for a 8,000 ft. lateral. Total well costs include drilling, completions, allocated pad level and production equipment (2) Appalachian peers include AR, COG, EQT, RICE, & RRC. Data obtained or recalculated from most recent peer company presentations. Marcellus Drilling Cost per Foot Marcellus Completion Cost per Stage ($000s) Upstream
18 Utica Shale Opportunities Permitted Drilling Completed Production SRC Vertical SRC Vertical + Horizontal SRC Planning 2.6 Bcf 2.4 Bcf 1.9 Bcf 1.6 Bcf 1.9 Bcf 1.6 Bcf SRC – CRV June 2016 Test 1.8 Bcf 2.2 Bcf SRC – Tract 007 March 2015 Test 2.4 Bcf Northeast Pa. Utica Well Results Estimated EUR/1,000 ft(1) WDA – CRV Test Results SRC - CRV SRC Tract 007 NC PA Industry Average Gross EUR/1,000 ft 1.6 Bcf 2.4 Bcf 2.0 Bcf Approx. NRI % 100% 82% 82% Net EUR/1,000 ft 1.6 Bcf 2.0 Bcf 1.6 Bcf Seneca’s WDA Utica also benefits from lack of royalty on fee-held acreage 2+ Bcf EDA – Tract 007 Test Results  Initial Test June 2016  Lateral Length 4,630 ft.  30 Day IP /1,000 ft 1.4 MMcf/d  Est. EUR /1,000 ft 1.8 Bcf  Initial Test March 2015  Lateral Length 4,640 ft  24 Hour IP 22.7 MMcf/d  Est. EUR /1,000 ft 2.4 Bcf 1st Clermont Rich Valley Utica Well Test On Trend with Northeast Pa. Results (1) Estimated by Seneca reservoir engineering. Industry estimates are base on publicly available information (e.g., Pa DEP). CRV Utica vs. North Central Pa. Upstream
19 WDA Utica Appraisal  Plan to drill 8 additional Utica appraisal wells off Marcellus development pads  Currently testing 2nd well (NF-A pad)  Seeking to optimize target zone and D&C design  Evaluation will consider competitiveness with Marcellus economics  Expect Utica WDA development costs to be $5.5 to $6.5 million per well  Will use existing pad, water and gathering infrastructure from Marcellus development to drive efficiencies WDA UTICA TESTING TIMELINE Pad # Wells Status Test Timing (FY) 1 E09-M 1 Producing Initial On-line 2 NF-A 1 Completed Sand Q1 '17 3 E09-S 2 TD’d Target Q3 '17 4 C09-D 1 Planned Step-out Q3 '17 5 D08-U 3 Planned Target Q2 '18 6 E08-T 1 Planned Step-out Q3 '18 Next Steps 1 2 3 4 5 6 Upstream
20 Midstream Businesses $137 $161 $186 $188 $199 $15 $30 $64 $69 $79 $152 $191 $250 $257 $278 2012 2013 2014 2015 2016 Fiscal Year Pipeline & Storage Segment Gathering Segment MidstreamMidstream Midstream Businesses Adjusted EBITDA ($MM) Note: A reconciliation of Adjusted EBITDA to Net Income as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation. Midstream Businesses System Map NFG Supply Corp. FERC-Regulated Pipeline & Storage Empire Pipeline, Inc. FERC-Regulated Pipeline & Storage NFG Midstream Corp Marcellus & Utica Gathering & Compression
21 Integrated Development – WDA Gathering System Current System In-Service  ~67 miles of pipe/26,220 HP of compression  Current Capacity: 470 MMcf per day  Interconnects with TGP 300  Total CapEx To Date: $261million Fiscal 2017 Capital Plans  FY17 CapEx: $40 to $50 million  Adjusted timing of gathering & compression investment to match Seneca’s modified development schedule/Northern Access Future Build-Out  Ultimate capacity can exceed 1 Bcf/d  Over 300 miles of pipelines and five compressor stations (+60,000 HP installed)  Deliverability into TGP 300 and NFG Supply Gathering System Build-Out Tailored to Accommodate Seneca’s WDA Development Clermont Gathering System Map Midstream
22 Integrated Development – EDA Gathering Systems  In-Service Date: November 2009  Capital Expenditures (to date): $33 Million  Capacity: 220,000 Dth per day  Production Source: Seneca Resources – Tioga Co. (Covington and DCNR Tract 595 acreage)  Interconnect: TGP 300  Facilities: Pipelines and dehydration  Future third-party volume opportunities  In-Service Date: May 2012  Capital Expenditures (to date): $167 Million  Capacity: 466,000 to 585,000 Dth per day  Production Source: Seneca Resources – Lycoming Co. (DCNR Tract 100 and Gamble acreage)  Interconnect: Transco – Leidy Lateral  Facilities: Pipelines, compression, and dehydration  Future third-party volume opportunities Covington Gathering System Trout Run Gathering System Gathering Segment Supporting Seneca’s EDA Production & Future Development Interconnects Midstream
23 Northern Access Expansions for Seneca Resources Northern Access 2015  Customer: Seneca Resources (NFG)  In-Service: November 2015(1)  System: NFG Supply Corp.  Capacity: 140,000 Dth per day o Leased to TGP as part of TGP’s Niagara Expansion project  Delivery Interconnect: o Niagara (TransCanada)  Major Facilities: o 23,000 hp Compression  Total Cost: $67.1 million  Annual Revenues: $13.3 million Expanding Our Interstate Pipelines to Deliver Seneca’s WDA Production to Canada Niagara Midstream (1) 40,000 Dth per day went in-service on November 1, 2015. The remaining 100,000 Dth per day was placed in-service on December 1, 2015.
24 Northern Access Expansions for Seneca Resources Northern Access 2016  Customer: Seneca Resources (NFG)  In-Service: Now targeting Nov. 1, 2017  Capacity: 490,000 Dth/d  Receipt Interconnect: o Clermont Gathering System (McKean Pa.) • Delivery Interconnects: o TransCanada – Chippawa (350 MDth/d) o TGP 200 – East Aurora (140 MDth/d)  Total Expected Cost: ~$455 Million  Major Facilities: o 98.5 miles – 16” & 24” Pipeline o 22,214 hp & 5,350 hp Compression  FERC/Regulatory Status: o FERC Environmental Assessment received 7/27/16 – Certificate expected late 2016 o NY DEC 401 Water Quality permit expected March 2017 Northern Access 2016 to Increase Transport Capacity Out of WDA by 490,000 Dth/d by FY18 Chippawa East Aurora Midstream
25 Recent 3rd Party Expansions Highly Successful Expansions for 3rd Parties since 2010 3rd Party Expansion Capital Cost ($MM) Annual Expansion Revenues Added ($MM) $72 $132 $183 Northern Access 2012 Empire & Lamont Line N Projects $387 million since FY 2010 $4 $37 $19 $4 $5 $27 ~$95 $0 $25 $50 $75 $100 FY11 FY12 FY13 FY14 FY15 FY16 Cum. Line N Projects +633 MDth/d Northern Access 2012 +320 MDth/d Empire & Lamont Expansions +489 MDth/d 1,442 MDth/d since FY2010 Midstream
26 Empire System Expansion Empire North Expansion Project  Target In-Service: Fiscal 2019  System: Empire Pipeline  Target Market: o Marcellus & Utica producers in Tioga & Potter County, Pa.  Open Season Capacity: 300,000 Dth/d  Receipt Point: Jackson (Tioga Co., Pa.)  Delivery Points: o 180,000 Dth/d to Chippawa (TCPL) o Up to 158,000 Dth/d to Hopewell (TGP)  Estimated Cost: $185 million  Major Facilities: o 3 new compressor stations  FERC Status: o Open Season concluded Nov. 2015 fully subscribed o Precedent agreements currently in negotiations Planned Empire Expansion Will Provide Optionality for Northeast Pennsylvania Producers Midstream
27 2015 Pipeline Expansion Projects In-Service Westside Expansion & Modernization In-Service (October 2015) Tuscarora Lateral In-Service (November 2015) 2015 Completed Pipeline Expansion Projects  Total Cost: $64.8 million  Incremental annual revenues of $10.9 million on 49,000 Dth per day capacity  Preserves $16.1 million in annual revenues on existing FT (192,500 Dth/d) and retained storage (3.3 Bcf) services  Total Cost: $82.3 million o Expansion: $43.3 million o Modernization: $39 million  Incremental Annual Revenues: $8.8 million  Capacity: 175,000 Dth per day o Range Resources (145,000 Dth/d) o Seneca Resources (30,000 Dth/d) Tuscarora Lateral Westside Expansion & Modernization Midstream
28 Pipeline & Storage Customer Mix Producer 35% LDC 47% Marketer 10% Outside Pipeline 6% End User 2% 4.1 MMDth/d (1) Contracted as of 10/20/2016. Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity) 60% 6% 20% 46% 40% 94% 80% 54% LDCs Producers Marketers Firm Storage Affiliated Non-Affiliated Firm Transport Midstream
29 California Overview Exploration & Production
30 California 1 4,500 500 1,200 1,700 800 3,640 1,760 1,000 1,680 1,350 770 North Midway Sunset South Midway Sunset North Lost Hills South Lost Hills Sespe East Coalinga FY 2010 FY 2016 Stable Oil Production | Minimal Capital Investment | Free Cash Flow Positive 2 3 4 5 6 Location Formation Production Method 1 East Coalinga Tremblor Primary 2 North Lost Hills Tulare & Etchegoin Primary/ Steamflood 3 South Lost Hills Monterey Shale Primary 4 North Midway Sunset Tulare & Potter Steamflood 5 South Midway Sunset Antelope Steamflood 6 Sespe Sespe Primary Gross Daily Production by Location (Boe/d) Upstream
31 California Average Daily Net Production $35-$45 Million Annual Capital Spending Needed to Keep CA Production Flat 9,322 9,078 9,699 9,674 9,315 ~9,600 2012 2013 2014 2015 2016 2017 Forecast Fiscal Year Upstream California Average Net Daily Production (BOE/D)California Annual Capital Expenditures ($MM) $63 $105 $83 $57 $38 $35-$45 2012 2013 2014 2015 2016 2017 Forecast Fiscal Year
32 34% 56% ~23% NMWSS SMWSS Farm-in Projects Economic Development Focused on Midway Sunset  Modest near-term capital program focused on locations that earn attractive returns in current oil price environment  A&D will focus on low cost, bolt-on opportunities  Sec. 17 and Pioneer farm-ins to provide future growth  F&D (est.) = $6.50/Boe Pioneer South MWSS Acreage North MWSS Acreage Sec. 17N North South South North Midway Sunset Economics MWSS Project IRRs at $50/Bbl(1) (1) Reflects pre-tax IRRs at a $50/Bbl WTI. Upstream
33 Strong Margins Support Significant Free Cash Flow $11.60 $3.23 $4.49 $2.46 $1.94 $29.34 Non-Steam Fuel LOE Steam Fuel G&A Production & Other Taxes Other Operating Costs Adjusted EBITDA West Division Adjusted EBITDA per BOE(1) Trailing 12-months Ended 9/30/16 Average Revenue Less: Cash Costs = Adjusted EBITDA $ 23.72 $ 53.06 $ 29.34 California Margins (per BOE) (1) Average revenue per BOE includes impact of hedging and other revenues. Note: A reconciliation of Adjusted EBITDA margin to Net Income as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation. EBITDA per BOE includes Seneca corporate results and eliminations. Upstream
34 Production and Marketing Exploration & Production
35 Proved Reserves & Development Costs 42.9 41.6 38.5 33.7 29.0 988 1,300 1,683 2,142 1,675 1,246 1,549 1,914 2,344 1,849 0 500 1,000 1,500 2,000 2,500 3,000 2012 2013 2014 2015 2016 At September 30 Natural Gas (Bcf) Crude Oil (MMbbl) (1)  117% Reserve Replacement Rate (adjusted for revisions and sales)  65% Proved Developed  35% Proved Undeveloped (1) Includes approximately 69 Bcf of natural gas proved reserves in Appalachia that will be transferred in fiscal 2017 as interests in the joint development wells are conveyed to the partner. (2) Reflects 246 Bcfe of natural gas reserves that were conveyed and sold to joint development partner and 16 Bcfe of Upper Devonian sales (3) FY 2016 net negative revisions include 227 Bcfe of proved reserves that were revised due to lower oil and gas pricing. Total Proved Reserves (Bcfe) Upstream Proved Reserves - FYE '15 2,344 FY '16 Production (161) Mineral Sales(2) (262) Net Negative Revisions(3) (262) Extensions & Discoveries 190 Proved Reserves - FYE '16 1,849 Fiscal 2016 Proved Reserves Reconciliation (Bcfe) Fiscal 2016 Proved Reserves Stats
36 Seneca Resources Net Production (Bcfe) Seneca Production 20.5 20.0 21.2 21.2 20.5 20-22 62.9 100.7 139.3 136.6 140.6 125-14883.4 120.7 160.5 157.8 161.1 145-170 0 50 100 150 200 250 2012 2013 2014 2015 2016 2017E Appalachia West Coast (California) (1) Joint Development Agreement tempers net production growth in FY17 (1) Refer to slide 39 for additional details on fiscal 2016 firm sales and local Appalachian spot market exposure.  Gross production expected to grow ~10%  Growth is largely being generated from joint development wells where Seneca has 26% NRI, resulting in flat net production YOY  Growth will in gross production will benefit NFG Midstream businesses:  Gathering segment throughput and revenues  Utilization of firm transport capacity on NFG pipelines (Northern Access) Upstream
37 Long-Term Contracts Supporting Appalachian Growth - 250 500 750 1,000 2017 2018 2019 2020 2021 2022 Fiscal Year Start Firm Sales(1) (1) Includes base firm sales contracts not tied to firm transportation capacity. Base firm sales are either fixed priced or priced at an index (e.g., NYMEX ) +/- a fixed basis and do not carry any transportation costs. See slide 39 for details on firm sales portfolio for fiscal 2017. (2) Includes capacity on both National Fuel Gas Supply Corp. and Empire Pipeline, Inc., both wholly owned subsidiaries of National Fuel Gas Company. Atlantic Sunrise (Transco) Delivery Markets: Mid-Atlantic & Southeast U.S. 189,405 Dth/d Northern Access 2016 (NFG(2), TransCanada & Union) Delivery Markets: Canada-Dawn & NY-TGP200 490,000 Dth/d Niagara Expansion (TGP & NFG) Delivery Markets: Canada-Dawn & TETCO 170,000 Dth/d Northeast Supply Diversification 50,000 Dth/d Gross Firm Sales and Firm Transport Volumes Under Contract (Thousands Dth per Day) Atlantic Sunrise now expected July 2018 Northern Access on track for Nov. 2017 ~500 MDth/d gross production sold on firm basis in FY17 Upstream
38 Firm Transportation Commitments Volume (Dth/d) Production Source Delivery Market Demand Charges ($/Dth) Gas Marketing Strategy Northeast Supply Diversification Project Tennessee Gas Pipeline Atlantic Sunrise WMB - Transco In-service: Mid-2018(1) Niagara Expansion TGP & NFG Northern Access NFG – Supply & Empire In-Service: Nov. 1 2017 50,000 189,405 158,000 350,000 EDA -Tioga County Covington & Tract 595 EDA - Lycoming County Tract 100 & Gamble WDA – Clermont/ Rich Valley WDA – Clermont /Rich Valley 12,000 140,000 Canada (Dawn) Mid-Atlantic/ Southeast Canada (Dawn) TETCO (SE Pa.) Canada (Dawn) TGP 200 (NY) $0.50 (3rd party) $0.73 (3rd party) NFG pipelines = $0.24 3rd party = $0.43 NFG pipelines = $0.12 NFG pipelines = $0.38 NFG pipelines = $0.50 3rd party = $0.21 Firm Sales Contracts 50,000 Dth/d Dawn/NYMEX+ 10 years CurrentlyIn-ServiceFutureCapacity Firm Sales Contracts 158,000 Dth/d Dawn/NYMEX+ 8 to 15 years Firm Sales Contracts 189,405 Dth/d NYMEX+ First 5 years Firm Sales Contracts 145,000 Dth/d Dawn/Fixed Price First 3 years (1) WMB is now targeting s the middle of calendar 2018 following the change in the timing of the environmental review from FERC. Upstream
39 Firm Sales Provide Market for Appalachian Production 105,800 Plus $0.03 93,800 Less $0.01 161,200 Less $0.17 170,500 Less $0.17 33,300 Less $0.33 29,800 Less $0.33 58,200 Less $0.01 61,600 Less $0.02 19,400 Less $0.02 21,000 Less $0.02 158,500 $2.45 160,200 $2.56 145,000 $2.45 146,400 $2.45 355,800 345,400 325,600 337,900 Q1 FY17 Q2 FY17 Q3 FY17 Q4 FY17 Fixed Price Dawn DOM SP NYMEX Gross vs. Net Firm Sales Volumes (Dth per Day) Q1 FY17 Q2 FY17 Q3 FY17 Q4 FY17 Gross 493,000/d 483,000/d 483,000/d 483,000/d NRI Owners(2) 137,200/d 137,600/d 157,400/d 145,100/d Net 355,800/d 345,400/d 325,600/d 337,900/d FY 17 Net Contracted Volumes (Dth per day) Contracted Index Price Differentials ($ per Dth)(1) (1) Values shown represent the price or differential to a reference price (netback price) at the point of sale. (2) Reflects adjustment to gross sales volumes to reflect impact of lease royalties in EDA and net revenue interests assigned to joint development partner on certain contracts in WDA. Upstream
40 Strong Hedge Book in Fiscal 2017 Natural Gas Swap & Fixed Physical Sales Contracts (Millions MMBtu) 35.7 42.6 27.1 16.9 6.5 22.1 8.4 7.2 7.2 56.2 32.1 12.2 120.5 83.1 46.5 27.7 - 50.0 100.0 150.0 FY 2017 FY 2018 FY 2019 FY 2020 NYMEX Dominion Dawn & MichCon Fixed Price Physical Sales Fiscal 2017 Natural Gas Production 83% hedged(1) at $3.38 per MMBtu (2) (1) Assumes midpoint of natural gas production guidance, adjusted for year-to-date actual results. (2) Fixed price physical sales exclude joint development partner’s share of fixed price contract WDA volumes as specified under the joint development agreement. Upstream
41 Fiscal 2017 Production and Price Certainty 145 – 170 Bcfe 116 Bcf 4 Bcf(2) 5 - 28 Bcf(3) 20-22 Bcfe Firms Sales + Hedges Firm Sales (Unhedged) Spot Exposure California Total Seneca FINANCIAL HEDGE + FIRM SALE = PRICE CERTAINTY (1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and firm transportation costs. (2) Indicates firm sales contracts with fixed index differentials but not backed by a matching NYMEX financial hedge. (3) Includes non-operated production from Western Development Area (legacy EOG JV wells) of ~5 Bcf.  116 Bcf realizing net ~$3.10/Mcf (1)  4 Bcf of Additional Basis Protection Upstream
42 $1.52 $0.87 $0.65 - $0.75 FY 2015 FY 2016 FY 2017E $0.59 $0.59 $0.59 $0.22 $0.14 $0.12 $0.81 $0.73 $0.71 FY 2015 FY 2016 FY 2017E Gathering & Transport LOE (non-Gathering) G&A Taxes & Other Operating Costs  Competitive, low cost structure in Appalachia and California supports strong cash margins  Gathering fee generates significant revenue stream for affiliated gathering company  DD&A decrease due to improving Marcellus F&D costs and reduction in net plant resulting from ceiling test impairments DD&A $/Mcfe $0.52 $0.52 $0.50 $0.54 $0.44 $0.50 $0.42 $0.39 $0.38 $0.22 $0.17 $0.20 $1.70 $1.52 $1.58 FY 2015 FY 2016 FY 2017E $16.17 $14.83 $17.73 FY 2015 FY 2016 FY 2017E Appalachia LOE & Gathering $/Mcfe California LOE $/Boe Seneca Resources Consolidated $/Mcfe (1) (2) (2) (1) (1) Excludes $7.9 million , or $0.05 per Mcfe, of professional fees relating to the joint development agreement announced in December 2015. (2) The total of the two LOE components represents the midpoint of the LOE guidance range of $0.95 to $1.05 per Mcfe for fiscal 2017. Upstream
43 Downstream Overview Utility ~ Energy Marketing
44 NewYork & Pennsylvania Service Territories New York Total Customers(1): 528,312 ROE: 9.1% (NY PSC Rate Case Settlement, May 2014) Rate Mechanisms: o Earnings Sharing o Revenue Decoupling o Weather Normalization o Low Income Rates o Merchant Function Charge (Uncollectibles Adj.) o 90/10 Sharing (Large Customers) Filed Rate Case with NY PSC on 4/28/16 Pennsylvania Total Customers(1): 213,924 ROE: Black Box Settlement (2007) Rate Mechanisms: o Low Income Rates o Merchant Function Charge (1) As of September 30, 2016. Downstream
45 NewYork Rate Case Key Drivers • Requesting rate relief that would increase annual revenues by $41.7 million • Key drivers of revenue requirement:  Significant increase in net plant - $127.5 million - and related depreciation expense since 9/30/2006, the test year associated with the 2007 rate proceeding  Continued investment in pipeline replacement and system modernization to enhance and ensure safe, reliable service • Accelerated removal of vintage pipe from current annual target of 95 miles to 110 miles • Replacement of aging information technology infrastructure completed in 2nd half of FY16  Commitment to low income customer, conservation and gas expansion initiatives Timeline April 28, 2016 Request filed with NY PSC for $41.7mm in rate relief August 26, 2016 NY DPS Staff and Intervenor Testimony Filed April 27, 2017 Approximate date that revised rates may become effective (subject to “make whole” request) September 16, 2016 Rebuttal Testimony filed October 5-7, 2016 Evidentiary Hearings in Albany, NY Background On April 28, 2016, National Fuel Gas Distribution Corporation filed a request with the New York Public Service Commission (NY PSC) to amend its tariff and increase its base rates. National Fuel’s base rates have not changed since the last base rate case was litigated in 2007. October 19, 2016 Filed Notice of Impending Confidential Settlement Negotiations and request for 1 month extension of suspension period with “make whole” provision Downstream
46 92 94 96 98 100 102 104 106 Residential (Mcf) 20 25 30 35 40 Industrial (MMcf) Utility: Shifting Trends in Customer Usage (1) Weighted Average of New York and Pennsylvania service territories (assumes normal weather). Usage Per Account (1) 12-Months Ended September 30 Downstream
47 Utility: Strong Commitment to Safety $43.8 $48.1 $49.8 $54.4 $61.8$58.3 $72.0 $88.8 $94.4 $98.0 $90 - $100 $0.0 $30.0 $60.0 $90.0 $120.0 $150.0 2012 2013 2014 2015 2016 2017E Fiscal Year Capital Expenditures for Safety Total Capital Expenditures Recent increase due to ~$60MM upgrade of the Utility’s Customer Information System and anticipated acceleration of pipeline replacement program The Utility remains focused on maintaining the ongoing safety and reliability of its system Capital Expenditures ($ millions) Downstream
48 A Proven History of Controlling Costs $152 $152 $151 $163 $160 $16 $20 $33 $28 $23$9 $6 $10 $9 $7$177 $178 $193 $200 $189 $0 $50 $100 $150 $200 $250 2012 2013 2014 2015 2016 Fiscal Year All Other O&M Expenses O&M Pension Expense O&M Uncollectible Expense Capital Expenditures ($ millions) Downstream
49 Appendix
50 Seneca Resources $63 $105 $83 $57 $38 $35-$45 $631 $428 $520 $500 $61 $145-$175 $694 $533 $603 $557 $99 $180-$220 $0 $200 $400 $600 $800 2012 2013 2014 2015 2016E 2017E Fiscal Year Appalachia West Coast (California) (2) (1) (1) FY2016 and FY 2017 capital expenditure guidance reflects the netting of up-front and recurring proceeds received from joint development partner for working interest in joint development wells. (2) Seneca’s West Coast division includes Seneca corporate and eliminations. Capital Expenditures by Division ($ millions) Appendix
51 Marcellus Operated Well Results EDA Development Wells: Area Producing Well Count Average IP Rate (MMcfd) Average 30-Day (MMcf/d) Average Treatable Lateral Length (ft) Covington Tioga County 47 5.2 4.1 4,023’ Tract 595 Tioga County 44(2) 7.4 4.9 4,754’ Tract 100 Lycoming County 60(2) 17.0 12.6 5,221’ Area Producing Well Count Average IP Rate (MMcfd) Average 30-Day (MMcf/d) Average Treatable Lateral Length (ft) Clermont/Rich Valley (CRV) & Hemlock Elk, Cameron & McKean counties 107(1) 6.9 5.2 (2) 7,072’ WDA Development Wells: (1) Excludes 2 wells now operated by Seneca that were drilled by another operator as part of a joint-venture. Excludes 1 well producing from the Utica shale. (2) 30-day average excludes 7 wells that have not been on line 30 days. (3) Excludes 1 well each drilled into and producing from the Geneseo Shale in Tract 595 and Tract 100. Appendix
52 Marcellus Shale Program Economics (1) Internal Rate of Return (IRR) is pre-tax and includes estimated well costs under current cost structure, LOE, and Gathering tariffs anticipated for each prospect. (2) Net realized price reflects either (a) price received at the well-head or (b) price received at delivery market net of firm transportation charges. ~1,150 Locations Economic Below $2.00/MMBtu $3.00 IRR % (1) $2.75 IRR % (1) $2.50 IRR % (1) DCNR 100 Dry Gas (1033 BTU) 12 5,400 13-14 74% 53% 35% $1.48 Gamble Dry Gas (1033 BTU) 43 4,600 11-12 57% 42% 25% $1.59 CRV Dry Gas (1045 BTU) 53 8,000 8.5-9.5 27% 19% 13% $1.82 Hemlock / Ridgway Dry Gas (1045 BTU) 631 8,800 8-9 29% 21% 13% $1.79 Remaining Tier 1 Dry Gas (1045 BTU) 406 8,500 7-8 25% 17% 10% $1.91 Anticipated Delivery Market Niagara Expansion Northern Access Canada (Dawn) / TGP200 Atlantic Sunrise Southeast US (NYMEX+) Net Realized Price (2) Required for 15% IRR WDAEDA NYMEX / DAWN Pricing Prospect Product Locations Remaining to Be Drilled Completed Lateral Length (ft) Average EUR (Bcf) Appendix
53 Hedge Positions Natural Gas Volumes in thousand MMBtu; Prices in $/MMBtu Volume Avg. Price Volume Avg. Price Volume Avg. Price Volume Avg. Price Volume Avg. Price NYMEX Swaps 35,710 $4.29 42,570 $3.34 27,060 $3.17 16,880 $3.07 4,840 $3.01 Dominion Swaps 6,540 $3.86 - - - - - - - - MichCon Swaps 3,000 $4.10 - - - - - - - - Dawn Swaps 19,100 $3.70 8,400 $3.08 7,200 $3.00 7,200 $3.00 600 $3.00 Fixed Price Physical 56,150 $2.60 29,366 $2.46 11,947 $3.09 3,567 $3.24 - - Total 120,500 $3.38 80,336 $2.99 46,207 $3.13 27,647 $3.07 5,440 $3.01 Crude Oil Volumes & Prices in Bbl Avg. Avg. Avg. Price Price Price Brent Swaps 123,000 $92.27 24,000 $91.00 - - NYMEX Swaps 1,185,000 $61.34 663,000 $55.19 300,000 $53.00 Total 1,308,000 $64.25 687,000 $56.44 300,000 $53.00 Fiscal 2021 Vol. Vol. Fiscal 2019 Fiscal 2020Fiscal 2017 Fiscal 2018 Fiscal 2017 Fiscal 2018 Fiscal 2019 Vol. (1) (1) Fixed price physical sales exclude joint development partner’s share of fixed price contract WDA volumes as specified under the joint development agreement. Appendix
54 Comparable GAAP Financial Measure Slides & Reconciliations This presentation contains certain non-GAAP financial measures. For pages that contain non-GAAP financial measures, pages containing the most directly comparable GAAP financial measures and reconciliations are provided in the slides that follow. The Company believes that its non-GAAP financial measures are useful to investors because they provide an alternative method for assessing the Company’s ongoing operating results and for comparing the Company’s financial performance to other companies. The Company’s management uses these non-GAAP financial measures for the same purpose, and for planning and forecasting purposes. The presentation of non-GAAP financial measures is not meant to be a substitute for financial measures prepared in accordance with GAAP. The Company defines Adjusted EBITDA as reported GAAP earnings before the following items: interest expense, depreciation, depletion and amortization, interest and other income, impairments, items impacting comparability and income taxes. Appendix
55 Non-GAAP Reconciliations – Adjusted EBITDA Appendix Reconciliation of Adjusted EBITDAto Consolidated Net Income ($ Thousands) FY 2012 Total Adjusted EBITDA Exploration & Production Adjusted EBITDA 397,129$ 492,383$ 539,472$ 422,289$ 363,830$ Pipeline & Storage Adjusted EBITDA 136,914 161,226 186,022 188,042 199,446 Gathering Adjusted EBITDA 14,814 29,777 64,060 68,881 78,685 Utility Adjusted EBITDA 159,986 171,669 164,643 164,037 148,683 Energy Marketing Adjusted EBITDA 5,945 6,963 10,335 12,237 6,655 Corporate & All Other Adjusted EBITDA (10,674) (9,920) (11,078) (11,900) (8,238) Total Adjusted EBITDA 704,114$ 852,098$ 953,454$ 843,586$ 789,061$ Total Adjusted EBITDA 704,114$ 852,098$ 953,454$ 843,586$ 789,061$ Minus: Interest Expense (86,240) (94,111) (94,277) (99,471) (121,044) Plus: Interest and Other Income 8,822 9,032 13,631 11,961 14,055 Minus: Income Tax Expense (150,554) (172,758) (189,614) 319,136 232,549 Minus: Depreciation, Depletion & Amortization (271,530) (326,760) (383,781) (336,158) (249,417) Minus: Impairment of Oil and Gas Properties (E&P) - - - (1,126,257) (948,307) Plus: Reversal of Stock-Based Compensation - - - 7,776 - Plus: Elimination of Other Post-Retirement Regulatory Liability (P&S) 21,672 - - - - Minus: Pennsylvania Impact Fee Related to Prior Fiscal Years (E&P) (6,206) - - - - Minus: New York Regulatory Adjustment (Utility) - (7,500) - - - Minus: Joint Development Agreement Professional Fees - - - - (7,855) Rounding (1) - - - Consolidated Net Income 220,077$ 260,001$ 299,413$ (379,427)$ (290,958)$ Consolidated Debt to Total Adjusted EBITDA Long-Term Debt, Net of Current Portion (End of Period) 1,149,000$ 1,649,000$ 1,649,000$ 2,099,000$ 2,099,000$ Current Portion of Long-Term Debt (End of Period) 250,000 - - - - Notes Payable to Banks and Commercial Paper (End of Period) 171,000 - 85,600 - - Total Debt (End of Period) 1,570,000$ 1,649,000$ 1,734,600$ 2,099,000$ 2,099,000$ Long-Term Debt, Net of Current Portion (Start of Period) 899,000 1,149,000 1,649,000 1,649,000 2,099,000 Current Portion of Long-Term Debt (Start of Period) 150,000 250,000 - - - Notes Payable to Banks and Commercial Paper (Start of Period) 40,000 171,000 - 85,600 - Total Debt (Start of Period) 1,089,000$ 1,570,000$ 1,649,000$ 1,734,600$ 2,099,000$ Average Total Debt 1,329,500$ 1,609,500$ 1,691,800$ 1,916,800$ 2,099,000$ Average Total Debt to Total Adjusted EBITDA 1.89 x 1.89 x 1.77 x 2.27 x 2.66 x FY 2013 FY 2014 FY 2015 FY 2016
56 Non-GAAP Reconciliations – Capital Expenditures Appendix Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures ($ Thousands) FY 2017 FY 2012 FY 2013 FY 2014 FY 2015 FY 2016 Forecast Capital Expenditures from Continuing Operations Exploration & Production Capital Expenditures 693,810$ 533,129$ 602,705$ 557,313$ 256,104$ $180,000 - $220,000 Pipeline & Storage Capital Expenditures 144,167 56,144$ 139,821$ 230,192$ 114,250$ $390,000 - $440,000 Gathering Segment Capital Expenditures 80,012 54,792$ 137,799$ 118,166$ 54,293$ $65,000 - $75,000 Utility Capital Expenditures 58,284 71,970$ 88,810$ 94,371$ 98,007$ $90,000 - $100,000 Energy Marketing, Corporate & All Other Capital Expenditures 1,121 1,062$ 772$ 467$ 397$ Total Capital Expenditures from Continuing Operations 977,394$ 717,097$ 969,907$ 1,000,509$ 523,051$ $725,000 - $835,000 Plus (Minus) Accrued Capital Expenditures Exploration & Production FY 2016 Accrued Capital Expenditures -$ -$ -$ -$ (25,215)$ Exploration & Production FY 2015 Accrued Capital Expenditures - - - (46,173) 46,173 Exploration & Production FY 2014 Accrued Capital Expenditures - - (80,108) 80,108 - Exploration & Production FY 2013 Accrued Capital Expenditures - (58,478) 58,478 - - Exploration & Production FY 2012 Accrued Capital Expenditures (38,861) 38,861 - - - Exploration & Production FY 2011 Accrued Capital Expenditures 103,287 - - - - Pipeline & Storage FY 2016 Accrued Capital Expenditures - - - - (18,661) Pipeline & Storage FY 2015 Accrued Capital Expenditures - - - (33,925) 33,925 Pipeline & Storage FY 2014 Accrued Capital Expenditures - - (28,122) 28,122 - Pipeline & Storage FY 2013 Accrued Capital Expenditures - (5,633) 5,633 - - Pipeline & Storage FY 2012 Accrued Capital Expenditures (12,699) 12,699 - - - Pipeline & Storage FY 2011 Accrued Capital Expenditures 16,431 - - - - Gathering FY 2016 Accrued Capital Expenditures - - - - (5,355) Gathering FY 2015 Accrued Capital Expenditures - - - (22,416) 22,416 Gathering FY 2014 Accrued Capital Expenditures - - (20,084) 20,084 - Gathering FY 2013 Accrued Capital Expenditures - (6,700) 6,700 - - Gathering FY 2012 Accrued Capital Expenditures (12,690) 12,690 - - - Gathering FY 2011 Accrued Capital Expenditures 3,079 - - - - Utility FY 2016 Accrued Capital Expenditures - - - - (11,203) Utility FY 2015 Accrued Capital Expenditures - - - (16,445) 16,445 Utility FY 2014 Accrued Capital Expenditures - - (8,315) 8,315 - Utility FY 2013 Accrued Capital Expenditures - (10,328) 10,328 - - Utility FY 2012 Accrued Capital Expenditures (3,253) 3,253 - - - Utility FY 2011 Accrued Capital Expenditures 2,319 - - - - Total Accrued Capital Expenditures 57,613$ (13,636)$ (55,490)$ 17,670$ 58,525$ Total Capital Expenditures per Statement of Cash Flows 1,035,007$ 703,461$ 914,417$ 1,018,179$ 581,576$ $725,000 - $835,000
57 Non-GAAP Reconciliations – E&P Adjusted EBITDA Reconciliation of Exploration & Production Adjusted EBITDAfor Appalachia and West Coast divisions to Exploration & Production Segment Net Income ($ Thousands) Appalachia West Coast Total E&P Appalachia West Coast Total E&P Reported GAAP Earnings 3,801$ 12,943$ 16,744$ (425,691)$ (27,151)$ (452,842)$ Depreciation, Depletion and Amortization 22,039 5,338 27,377 114,843 25,120 139,963 Interest and Other Income (78) - (78) (180) (678) (858) Interest Expense 12,920 632 13,552 53,066 2,368 55,434 Income Taxes 2,758 2,048 4,806 (307,737) (26,292) (334,029) Impairment of Oil and Gas Producing Properties 27,985 4,771 32,756 821,616 126,691 948,307 Joint Development Agreement Professional Fees - - - 7,855 - 7,855 Adjusted EBITDA 69,425$ 25,732$ 95,157$ 263,772$ 100,058$ 363,830$ Appalachia West Coast Total E&P Appalachia West Coast Total E&P Production: Gas Production (MMcf) 34,711 779 35,490 140,457 3,090 143,547 Oil Production (MBbl) 12 712 724 28 2,895 2,923 Total Production (Mmcfe) 34,783 5,051 39,834 140,625 20,460 161,085 Adjusted EBITDAMargin per Mcfe 2.00$ 5.09$ 2.39$ 1.88$ 4.89$ 2.26$ Total Production (Mboe) NM 842 NM NM 3,410 NM Adjusted EBITDAMargin per Boe NM 30.56$ NM NM 29.34$ NM Note: Seneca West Coast division includes Seneca corporate and eliminations. Three Months Ended September 30, 2016 Twelve Months Ended Setpember 30, 2016 Appendix
58 Non-GAAP Reconciliations – E&P Operating Expenses Appendix Reconciliation of Exploration & Production Segment Operating Expenses by Division ($000s unless noted otherwise) Appalachia West Coast(2) Total E&P Appalachia West Coast(2) Total E&P Appalachia West Coast(2) Total E&P Appalachia West Coast(2) Total E&P $/ Mcfe $ / Boe $ / Mcfe $/ Mcfe $ / Boe $ / Mcfe Operating Expenses: Gathering & Transportation Expense (1) $82,949 $309 $83,258 $0.59 $0.09 $0.52 $81,212 $435 $81,647 $0.59 $0.12 $0.52 Lease Operating Expense $20,402 $50,254 $70,656 $0.14 $14.74 $0.44 $29,510 $56,643 $86,153 $0.22 $16.04 $0.54 Lease Operating and Transportation Expense $103,351 $50,563 $153,914 $0.73 $14.83 $0.96 $110,722 $57,078 $167,800 $0.81 $16.17 $1.06 General & Administrative Expense $55,293 $15,305 $70,598 $0.39 $4.49 $0.44 $47,445 $18,669 $66,114 $0.35 $5.29 $0.42 All Other Operating and Maintenance Expense $6,228 $6,604 $12,832 $0.04 $1.94 $0.08 $5,296 $9,008 $14,304 $0.04 $2.55 $0.09 Property, Franchise and Other Taxes $5,403 $8,391 $13,794 $0.04 $2.46 $0.09 $9,046 $11,121 $20,167 $0.07 $3.15 $0.13 Total Taxes & Other $11,631 $14,995 $26,626 $0.08 $4.40 $0.17 $14,342 $20,129 $34,471 $0.11 $5.70 $0.22 Depreciation, Depletaion & Amortization $139,963 $0.87 $239,818 $1.52 Production: Gas Production (MMcf) 140,457 3,090 143,547 136,404 3,159 139,563 Oil Production (MBbl) 28 2,895 2,923 30 3,004 3,034 Total Production (Mmcfe) 140,625 20,460 161,085 136,584 21,183 157,767 Total Production (Mboe) 23,438 3,410 26,848 22,764 3,531 26,295 (1) Gathering and Transportation expense is net of any payments received from JDA partner for the partner's share of gathering cost (2) Seneca West Coast division includes Seneca corporate and eliminations. Twelve Months Ended September 30, 2016 Twelve Months Ended September 30, 2015

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National Fuel Gas Company Earnings Slides - Nov 2016

  • 1. 1 Investor Presentation Q4 Fiscal 2016 Update November 3, 2016
  • 2. 2 Safe Harbor For Forward Looking Statements This presentation may contain “forward-looking statements” as defined by the Private Securities Litigation Reform Act of 1995, including statements regarding future prospects, plans, objectives, goals, projections, estimates of oil and gas quantities, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new accounting rules, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions. Forward-looking statements involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, but there can be no assurance that management’s expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the forward-looking statements: Delays or changes in costs or plans with respect to Company projects or related projects of other companies, including difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators; governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which address, among other things, target rates of return, rate design and retained natural gas), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal; impairments under the SEC’s full cost ceiling test for natural gas and oil reserves; changes in the price of natural gas or oil; financial and economic conditions, including the availability of credit, and occurrences affecting the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions; factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas and oil reserves, including among others geology, lease availability, title disputes, weather conditions, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations; changes in laws, regulations or judicial interpretations to which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, real property, and exploration and production activities such as hydraulic fracturing; changes in price differentials between similar quantities of natural gas or oil at different geographic locations, and the effect of such changes on commodity production, revenues and demand for pipeline transportation capacity to or from such locations; other changes in price differentials between similar quantities of natural gas or oil having different quality, heating value, hydrocarbon mix or delivery date; the cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company; uncertainty of oil and gas reserve estimates; significant differences between the Company’s projected and actual production levels for natural gas or oil; changes in demographic patterns and weather conditions; changes in the availability, price or accounting treatment of derivative financial instruments; changes in economic conditions, including global, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services; the creditworthiness or performance of the Company’s key suppliers, customers and counterparties; economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities, acts of war, cyber attacks or pest infestation; significant differences between the Company’s projected and actual capital expenditures and operating expenses; changes in laws, actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company’s pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities; increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; or Increasing costs of insurance, changes in coverage and the ability to obtain insurance. Forward-looking statements include estimates of oil and gas quantities. Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible under existing economic conditions, operating methods and government regulations. Other estimates of oil and gas quantities, including estimates of probable reserves, possible reserves, and resource potential, are by their nature more speculative than estimates of proved reserves. Accordingly, estimates other than proved reserves are subject to substantially greater risk of being actually realized. Investors are urged to consider closely the disclosure in our Form 10-K available at www.nationalfuelgas.com. You can also obtain this form on the SEC’s website at www.sec.gov. For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements, see “Risk Factors” in the Company’s Form 10-K for the fiscal year ended September 30, 2015 and the Forms 10-Q for the quarters ended December 31, 2015, March 31, 2016 and June 30, 2016. The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence of unanticipated events.
  • 3. 3 Quality Assets - Exceptional Location - Unique Integration  1.8 Tcfe Proved Reserves (1)  785,000 net acres in Appalachia - mostly held in fee with no royalty  3 million Bbls per year of crude oil production in California  $278 million annual adjusted EBITDA (2)  $1.3+ billion midstream investments since 2010  Coordinated gathering and transmission infrastructure build-out with NFG Upstream  740,000 Utility customer accounts  Stable, regulated earnings & cash flows  Generates operational and financial synergies with other segments (1) Total proved reserves are as of September 30, 2016. See slide 35 for further discussion . (2) For the trailing twelve months ended September 30, 2016. A reconciliation of Adjusted EBITDA to Net Income as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation. Upstream Midstream Downstream
  • 4. 4 The National Fuel Value Proposition Unique Asset Mix and Integrated Model Provide Balance and Stability  Fee ownership on ~715,000 net acres in WDA = limited royalties or drilling commitments  Seneca has >900,000 Dth/day of firm transportation & sales contracts by end of fiscal 2018  Stacked pay potential in Utica and Geneseo shales across Marcellus acreage  Coordinated gathering & interstate pipeline infrastructure build-out with NFG midstream  Opportunity for further pipeline expansion to accommodate Appalachian supply growth Considerable Upstream and Midstream Growth Opportunities in Appalachia  Geographical and operational integration drives capital flexibility and reduces costs  Investment grade credit rating and liquidity to support long-term Appalachian growth strategy  Cash flow from rate-regulated businesses supports interest costs and funds the dividend Disciplined Approach To Capital Allocation and Returns on Investment  Capital allocation that is focused on earning economic returns  Strong hedge book helps insulate near-term earnings and cash flows from commodity volatility  Creating long-term, sustainable value remains our #1 shareholder priority
  • 5. 5 Adjusted EBITDA by Segment ($ millions) Balanced Earnings and Cash Flows $160 $172 $165 $164 $149 $137 $161 $186 $188 $199 $64 $69 $79 $397 $492 $539 $422 $364 $704 $852 $953 $843 $789 $0 $500 $1,000 $1,500 2012 2013 2014 2015 2016 Fiscal Year Exploration & Production Segment Gathering Segment Pipeline & Storage Segment Utility Segment Energy Marketing & Other Note: A reconciliation of Adjusted EBITDA to Net Income as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation. (1)
  • 6. 6 Flexibility to Responsibly Deploy Capital $58 $72 $89 $94 $98 $90 - $100 $144 $56 $140 $230 $114 $390 - $440 $80 $55 $138 $118 $54 $65 - $75 $694 $533 $603 $557 $99 $180 - $220 $977 $717 $970 $1,001 $366 $725-$835 $0 $500 $1,000 $1,500 2012 2013 2014 2015 2016 2017E Fiscal Year Exploration & Production Segment Gathering Segment Pipeline & Storage Segment Utility Segment Energy Marketing & Other (1) (1) FY 2016 actual capital expenditures reflects the netting of $157 million of up-front proceeds received from joint development partner for working interest in joint development wells. FY 2017 guidance also reflects the netting of anticipated proceeds received from the joint development partner. Note: A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. Capital Expenditures by Segment ($ millions) E&P Total NFG Gross CapEx $256 $523 JDA Proceeds ($157) ($157) Net CapEx $99 $366 CapEx Reconciliation for JDA Proceeds ($millions)
  • 7. 7 Strong Balance Sheet & Liquidity Total Equity 42% Total Debt 58% $3.6 Billion Total Capitalization as of September 30, 2016 1.89 x 1.89 x 1.77 x 2.27 x 2.66 x 2012 2013 2014 2015 2016 Fiscal Year End Debt/Adjusted EBITDA Capitalization Debt Maturity Profile ($MM) Liquidity Committed Credit Facilities Short-term Debt Outstanding Available Short-term Credit Facilities Cash Balance at 09/30/16 Total Liquidity at 09/30/16 $ 1,250 MM $ 0 MM $ 1,250 MM $ 130 MM $ 1,380 MM $300 $250 $500 $549 $500 $0 $200 $400 $600 Note: A reconciliation of Adjusted EBITDA to Net Income is included at the end of this presentation.
  • 8. 8 Dividend Track Record $0.00 $0.50 $1.00 $1.50 $2.00 Annual Rate at Fiscal Year End Annual Dividend Rate ($ /share) Consecutive Payments 114 Years Consecutive Increases 46 Years Current Dividend Rate $1.62 per Share Current Dividend Yield (1) 3.1% (1) As of November 2, 2016. NFG’s Dividend Consistency
  • 9. 9  Gathering: Just-in-time installation of gathering pipelines and compression facilities to accommodate Seneca growth  Pipeline & Storage: Construction of Northern Access (Nov. 17 in-service)  $455 million project (~$300mm to be spent in FY17)  Remain on track to receive regulatory approvals FY 2017 Capital Budget and Operating Plan (1) FY 2016 actual capital expenditures reflects the netting of $157 million of up-front proceeds received from joint development partner for working interest in joint development wells. FY 2017 guidance also reflects the netting of anticipated proceeds received from the joint development partner. Note: A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. $98 $90 - $100 $114 $390 - $440 $54 $65 - $75 $99 $180 - $220 $366 $725 - $835 $0 $250 $500 $750 $1,000 FY 2016 FY 2017 Forecast Exploration & Production Segment Gathering Segment Pipeline & Storage Segment Utility Segment Energy Marketing & Other (1) Upstream Capital Expenditures by Segment ($MM) FY2017 Operating Plan Highlights  Appalachia: 1-rig program / daylight-only frac crew  Development pace designed to utilize ~680Mdth/d of new FT available by the end of FY18  Flexibility to accelerate D&C to grow into FT efficiently  California: $35- $45 million capex to keep production flat Midstream Downstream  Utility: Planning to accelerate pipeline replacement in NY from 90 miles to 110 miles per year
  • 10. 10 Appalachia Overview Exploration & Production ~ Gathering ~ Pipeline & Storage
  • 11. 11 Integrated Vision for Long-term Growth in Appalachia 200,000 “Tier 1” fee-held acres in Pa. 1,050 locations economic < $2.00/MMBtu with minimal lease expiration Just-in-time build-out of Clermont Gathering System limits stranded pipeline assets/capital Northern Access projects to transport 660 MDth/d of Seneca- operated WDA production by FY18 Exploration & Production Pipeline & Storage Gathering 1 2 3 1 2 Long-term, return-driven approach to developing vast Marcellus & Utica acreage position Connecting Our Production to Our Interstate Pipeline System Expanding Our Interstate Pipeline System to Reach Premium Markets 3
  • 12. 12 Significant Appalachian Acreage Position  153 wells able to produce 270 MMcf/d  Mostly leased (16-18% royalty) with no significant near-term lease expirations  50-60 remaining Marcellus locations economic under $1.60/Mcf  Additional Utica & Geneseo potential  Limited development drilling until firm transportation on Atlantic Sunrise is available in mid-2018 Eastern Development Area (EDA) EDA - 70,000 Acres Western Development Area (WDA) WDA - 715,000 Acres  139 wells able to produce 290 MMcf/d  Large inventory of high quality Marcellus acreage economic under $2.00/Mcf  Fee ownership – lack of royalty enhances economics  Highly contiguous nature drives cost and operational efficiencies  660 MDth/d firm transportation by FY18 Fee Acreage Lease Acreage Upstream
  • 13. 13 Marcellus Shale: Western Development Area WDA Tier 1 Acreage – 200,000 Acres WDA Tier 1 Marcellus Economics(1) WDA Highlights  Large drilling inventory of quality Marcellus dry gas o ~1,100 locations economic < $2.00/MMBtu realized  Fee acreage provides flexibility / enhances economics o No royalty on most acreage o No lease expirations or requirements to drill acreage  Highly contiguous position drives best in class Marcellus well costs o Multi-well pad drilling averaging 10 wells with 8,000 ft. laterals o Water management operations lowering water costs to under $1 /Bbl  NFG midstream infrastructure supporting growth o NFG Clermont gathering system o NFG Northern Access projects 660 MDth/d firm transport to Dawn (Canada) and Midwest and northeast US markets  Early Utica test results in CRV on trend with other Utica wells in NE Pa. o Will have 8 Utica test wells on-line by end of FY 2018 (1) Internal rate of return (IRR) is pre-tax and includes estimated well costs under the current well design and cost structure and projected firm transportation, gathering, LOE and other operating costs. Avg Avg $3.00 15% IRR Locations Lateral EUR NYMEX/Dawn Realized Remaining Length (ft) (Bcf) IRR% Price CRV 53 8,000 8.5-9.5 27% $1.82 Hemlock/Ridgway 631 8,800 8-9 29% $1.79 Other Tier 1 406 8,500 7-8 25% $1.91 Clermont/ Rich Valley Hemlock Ridgway 2 - 4 BCF/well 7- 9.5 BCF/well 4 - 6 BCF/well EUR Color Key Upstream
  • 14. 14 WDA Clermont / Rich Valley Development  117 wells able to produce ~280 MMcf/d  Dropped to 1 rig in March 2016 (down from 3 rigs at start of fiscal 2016)  Rig additions planned to meet firm transport / sales obligations  Developing 75 wells with joint development partner (IOG)  63 wells drilled  50 wells online / producing  Just-in-time gathering infrastructure build- out provides significant capital flexibility to adjust scheduling and pace of Seneca’s development program  Regional focus of development minimizes capital outlay and improves returns CRV Development Summary Upstream
  • 15. 15  Assets: 75 current and future Marcellus development wells in the Clermont/Rich Valley region of Seneca’s WDA.  Locations Developed Under Initial Obligation: 39 wells  Remaining Locations to be Developed: 36 wells  Partner Option: IOG has one-time option to participate in a 7-well pad to be completed before December 31, 2017  Economics: IOG participates as an 80% working interest owner until the IOG achieves a 15% IRR hurdle. Seneca retains a 7.5% royalty and remaining 20% working interest.  Natural Gas Marketing: IOG to receive same realized price before hedging as Seneca on production from the joint development wells, including firm sales and the cost of firm transportation. Seneca WDA Joint Development Agreement (1) Estimated reduction in capital expenditures from joint development agreement assumes current wells costs. Transaction Key Terms of the Agreement On June 13, 2016, Seneca announced the extension of asset-level joint development agreement with IOG CRV – Marcellus Capital, LLC, an affiliate of IOG Capital, LP, and funds managed by affiliates of Fortress Investment Group LLC, to jointly develop Marcellus Shale natural gas assets located in the Western Development Area. Strategic Rationale  Significantly reduces near-term upstream capital spending Initial 39 wells - $170 million(1) Remaining 36 wells - $155 million(1)  Validates quality of Seneca’s Tier 1 Marcellus WDA acreage  Seneca maintains activity levels to continue to drive Marcellus drilling and completion efficiencies  Solidifies NFG’s midstream growth strategy: Gathering - All production from JV wells will flow through NFG Midstream’s Clermont Gathering System Pipeline & Storage - Provides production growth that will utilize the 660 MDth/d of firm transportation capacity on NFG’s Northern Access pipeline expansion projects available starting Nov. 1, 2017  Strengthened balance sheet and makes Seneca cash flow positive in near-term Seneca IOG Working Interest 20% 80% Net Revenue Interest 26% 74% Upstream
  • 16. 16 Marcellus Shale: Eastern Development Area EDA Acreage – 70,000 AcresEDA Highlights Covington & DCNR Tract 595 (Tioga Co., Pa.) • Marcellus locations fully developed • 92 wells(1) with 80 MMcf/d productive capacity • 70-80 MDth/d firm sales in FY17 • Production flows into NFG Covington Gathering System • Opportunity for future Geneseo & Utica development DCNR Tract 100 & Gamble (Lycoming Co., Pa.) • 61 wells(1) with 190 MMcf/d productive capacity • 115-160 MDth/d firm sales in FY17 • Atlantic Sunrise capacity (190 MDth/d) in mid-2018 • 55 remaining Marcellus locations economic < $1.60 /Mcf • Production flows into NFG Trout Run Gathering System • Geneseo well 24 IP test: 14.1MMcf/d on 4,920’ lat • Geneseo to provide 100-120 additional locations DCNR Tract 007 (Tioga Co., Pa) • 1 Utica and 1 Marcellus exploration well • Utica well 24 IP test: 22.7 MMcf/d • Expected to be placed on-line in Nov. 2016 • Utica Resource potential = ~1 Tcf over 70 well locations 3 1 2 (1) One well included in the total for both Tract 595 and Tract 100 is drilled into and producing from the Geneseo Shale. 3 1 2 Upstream
  • 17. 17 Best in Class Marcellus Well Costs $248 $148 $109 $91 $67 $58 $0 $100 $200 $300 2012 2013 2014 2015 2016 2017E $275 $208 $174 $153 $120 $110 $0 $100 $200 $300 2012 2013 2014 2015 2016 2017E Seneca Average Marcellus Well Cost(1) vs. Appalachian Peers (2) $663 $743 $800 $855 $867 $877 $988 $500 $600 $700 $800 $900 $1,000 Seneca CRV Peer 1 Peer 2 Industry Average Peer 3 Peer 4 Peer 5 $/lateralfoot (1) Seneca CRV reflects a $5.3 million “all-in” total well cost for a 8,000 ft. lateral. Total well costs include drilling, completions, allocated pad level and production equipment (2) Appalachian peers include AR, COG, EQT, RICE, & RRC. Data obtained or recalculated from most recent peer company presentations. Marcellus Drilling Cost per Foot Marcellus Completion Cost per Stage ($000s) Upstream
  • 18. 18 Utica Shale Opportunities Permitted Drilling Completed Production SRC Vertical SRC Vertical + Horizontal SRC Planning 2.6 Bcf 2.4 Bcf 1.9 Bcf 1.6 Bcf 1.9 Bcf 1.6 Bcf SRC – CRV June 2016 Test 1.8 Bcf 2.2 Bcf SRC – Tract 007 March 2015 Test 2.4 Bcf Northeast Pa. Utica Well Results Estimated EUR/1,000 ft(1) WDA – CRV Test Results SRC - CRV SRC Tract 007 NC PA Industry Average Gross EUR/1,000 ft 1.6 Bcf 2.4 Bcf 2.0 Bcf Approx. NRI % 100% 82% 82% Net EUR/1,000 ft 1.6 Bcf 2.0 Bcf 1.6 Bcf Seneca’s WDA Utica also benefits from lack of royalty on fee-held acreage 2+ Bcf EDA – Tract 007 Test Results  Initial Test June 2016  Lateral Length 4,630 ft.  30 Day IP /1,000 ft 1.4 MMcf/d  Est. EUR /1,000 ft 1.8 Bcf  Initial Test March 2015  Lateral Length 4,640 ft  24 Hour IP 22.7 MMcf/d  Est. EUR /1,000 ft 2.4 Bcf 1st Clermont Rich Valley Utica Well Test On Trend with Northeast Pa. Results (1) Estimated by Seneca reservoir engineering. Industry estimates are base on publicly available information (e.g., Pa DEP). CRV Utica vs. North Central Pa. Upstream
  • 19. 19 WDA Utica Appraisal  Plan to drill 8 additional Utica appraisal wells off Marcellus development pads  Currently testing 2nd well (NF-A pad)  Seeking to optimize target zone and D&C design  Evaluation will consider competitiveness with Marcellus economics  Expect Utica WDA development costs to be $5.5 to $6.5 million per well  Will use existing pad, water and gathering infrastructure from Marcellus development to drive efficiencies WDA UTICA TESTING TIMELINE Pad # Wells Status Test Timing (FY) 1 E09-M 1 Producing Initial On-line 2 NF-A 1 Completed Sand Q1 '17 3 E09-S 2 TD’d Target Q3 '17 4 C09-D 1 Planned Step-out Q3 '17 5 D08-U 3 Planned Target Q2 '18 6 E08-T 1 Planned Step-out Q3 '18 Next Steps 1 2 3 4 5 6 Upstream
  • 20. 20 Midstream Businesses $137 $161 $186 $188 $199 $15 $30 $64 $69 $79 $152 $191 $250 $257 $278 2012 2013 2014 2015 2016 Fiscal Year Pipeline & Storage Segment Gathering Segment MidstreamMidstream Midstream Businesses Adjusted EBITDA ($MM) Note: A reconciliation of Adjusted EBITDA to Net Income as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation. Midstream Businesses System Map NFG Supply Corp. FERC-Regulated Pipeline & Storage Empire Pipeline, Inc. FERC-Regulated Pipeline & Storage NFG Midstream Corp Marcellus & Utica Gathering & Compression
  • 21. 21 Integrated Development – WDA Gathering System Current System In-Service  ~67 miles of pipe/26,220 HP of compression  Current Capacity: 470 MMcf per day  Interconnects with TGP 300  Total CapEx To Date: $261million Fiscal 2017 Capital Plans  FY17 CapEx: $40 to $50 million  Adjusted timing of gathering & compression investment to match Seneca’s modified development schedule/Northern Access Future Build-Out  Ultimate capacity can exceed 1 Bcf/d  Over 300 miles of pipelines and five compressor stations (+60,000 HP installed)  Deliverability into TGP 300 and NFG Supply Gathering System Build-Out Tailored to Accommodate Seneca’s WDA Development Clermont Gathering System Map Midstream
  • 22. 22 Integrated Development – EDA Gathering Systems  In-Service Date: November 2009  Capital Expenditures (to date): $33 Million  Capacity: 220,000 Dth per day  Production Source: Seneca Resources – Tioga Co. (Covington and DCNR Tract 595 acreage)  Interconnect: TGP 300  Facilities: Pipelines and dehydration  Future third-party volume opportunities  In-Service Date: May 2012  Capital Expenditures (to date): $167 Million  Capacity: 466,000 to 585,000 Dth per day  Production Source: Seneca Resources – Lycoming Co. (DCNR Tract 100 and Gamble acreage)  Interconnect: Transco – Leidy Lateral  Facilities: Pipelines, compression, and dehydration  Future third-party volume opportunities Covington Gathering System Trout Run Gathering System Gathering Segment Supporting Seneca’s EDA Production & Future Development Interconnects Midstream
  • 23. 23 Northern Access Expansions for Seneca Resources Northern Access 2015  Customer: Seneca Resources (NFG)  In-Service: November 2015(1)  System: NFG Supply Corp.  Capacity: 140,000 Dth per day o Leased to TGP as part of TGP’s Niagara Expansion project  Delivery Interconnect: o Niagara (TransCanada)  Major Facilities: o 23,000 hp Compression  Total Cost: $67.1 million  Annual Revenues: $13.3 million Expanding Our Interstate Pipelines to Deliver Seneca’s WDA Production to Canada Niagara Midstream (1) 40,000 Dth per day went in-service on November 1, 2015. The remaining 100,000 Dth per day was placed in-service on December 1, 2015.
  • 24. 24 Northern Access Expansions for Seneca Resources Northern Access 2016  Customer: Seneca Resources (NFG)  In-Service: Now targeting Nov. 1, 2017  Capacity: 490,000 Dth/d  Receipt Interconnect: o Clermont Gathering System (McKean Pa.) • Delivery Interconnects: o TransCanada – Chippawa (350 MDth/d) o TGP 200 – East Aurora (140 MDth/d)  Total Expected Cost: ~$455 Million  Major Facilities: o 98.5 miles – 16” & 24” Pipeline o 22,214 hp & 5,350 hp Compression  FERC/Regulatory Status: o FERC Environmental Assessment received 7/27/16 – Certificate expected late 2016 o NY DEC 401 Water Quality permit expected March 2017 Northern Access 2016 to Increase Transport Capacity Out of WDA by 490,000 Dth/d by FY18 Chippawa East Aurora Midstream
  • 25. 25 Recent 3rd Party Expansions Highly Successful Expansions for 3rd Parties since 2010 3rd Party Expansion Capital Cost ($MM) Annual Expansion Revenues Added ($MM) $72 $132 $183 Northern Access 2012 Empire & Lamont Line N Projects $387 million since FY 2010 $4 $37 $19 $4 $5 $27 ~$95 $0 $25 $50 $75 $100 FY11 FY12 FY13 FY14 FY15 FY16 Cum. Line N Projects +633 MDth/d Northern Access 2012 +320 MDth/d Empire & Lamont Expansions +489 MDth/d 1,442 MDth/d since FY2010 Midstream
  • 26. 26 Empire System Expansion Empire North Expansion Project  Target In-Service: Fiscal 2019  System: Empire Pipeline  Target Market: o Marcellus & Utica producers in Tioga & Potter County, Pa.  Open Season Capacity: 300,000 Dth/d  Receipt Point: Jackson (Tioga Co., Pa.)  Delivery Points: o 180,000 Dth/d to Chippawa (TCPL) o Up to 158,000 Dth/d to Hopewell (TGP)  Estimated Cost: $185 million  Major Facilities: o 3 new compressor stations  FERC Status: o Open Season concluded Nov. 2015 fully subscribed o Precedent agreements currently in negotiations Planned Empire Expansion Will Provide Optionality for Northeast Pennsylvania Producers Midstream
  • 27. 27 2015 Pipeline Expansion Projects In-Service Westside Expansion & Modernization In-Service (October 2015) Tuscarora Lateral In-Service (November 2015) 2015 Completed Pipeline Expansion Projects  Total Cost: $64.8 million  Incremental annual revenues of $10.9 million on 49,000 Dth per day capacity  Preserves $16.1 million in annual revenues on existing FT (192,500 Dth/d) and retained storage (3.3 Bcf) services  Total Cost: $82.3 million o Expansion: $43.3 million o Modernization: $39 million  Incremental Annual Revenues: $8.8 million  Capacity: 175,000 Dth per day o Range Resources (145,000 Dth/d) o Seneca Resources (30,000 Dth/d) Tuscarora Lateral Westside Expansion & Modernization Midstream
  • 28. 28 Pipeline & Storage Customer Mix Producer 35% LDC 47% Marketer 10% Outside Pipeline 6% End User 2% 4.1 MMDth/d (1) Contracted as of 10/20/2016. Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity) 60% 6% 20% 46% 40% 94% 80% 54% LDCs Producers Marketers Firm Storage Affiliated Non-Affiliated Firm Transport Midstream
  • 30. 30 California 1 4,500 500 1,200 1,700 800 3,640 1,760 1,000 1,680 1,350 770 North Midway Sunset South Midway Sunset North Lost Hills South Lost Hills Sespe East Coalinga FY 2010 FY 2016 Stable Oil Production | Minimal Capital Investment | Free Cash Flow Positive 2 3 4 5 6 Location Formation Production Method 1 East Coalinga Tremblor Primary 2 North Lost Hills Tulare & Etchegoin Primary/ Steamflood 3 South Lost Hills Monterey Shale Primary 4 North Midway Sunset Tulare & Potter Steamflood 5 South Midway Sunset Antelope Steamflood 6 Sespe Sespe Primary Gross Daily Production by Location (Boe/d) Upstream
  • 31. 31 California Average Daily Net Production $35-$45 Million Annual Capital Spending Needed to Keep CA Production Flat 9,322 9,078 9,699 9,674 9,315 ~9,600 2012 2013 2014 2015 2016 2017 Forecast Fiscal Year Upstream California Average Net Daily Production (BOE/D)California Annual Capital Expenditures ($MM) $63 $105 $83 $57 $38 $35-$45 2012 2013 2014 2015 2016 2017 Forecast Fiscal Year
  • 32. 32 34% 56% ~23% NMWSS SMWSS Farm-in Projects Economic Development Focused on Midway Sunset  Modest near-term capital program focused on locations that earn attractive returns in current oil price environment  A&D will focus on low cost, bolt-on opportunities  Sec. 17 and Pioneer farm-ins to provide future growth  F&D (est.) = $6.50/Boe Pioneer South MWSS Acreage North MWSS Acreage Sec. 17N North South South North Midway Sunset Economics MWSS Project IRRs at $50/Bbl(1) (1) Reflects pre-tax IRRs at a $50/Bbl WTI. Upstream
  • 33. 33 Strong Margins Support Significant Free Cash Flow $11.60 $3.23 $4.49 $2.46 $1.94 $29.34 Non-Steam Fuel LOE Steam Fuel G&A Production & Other Taxes Other Operating Costs Adjusted EBITDA West Division Adjusted EBITDA per BOE(1) Trailing 12-months Ended 9/30/16 Average Revenue Less: Cash Costs = Adjusted EBITDA $ 23.72 $ 53.06 $ 29.34 California Margins (per BOE) (1) Average revenue per BOE includes impact of hedging and other revenues. Note: A reconciliation of Adjusted EBITDA margin to Net Income as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation. EBITDA per BOE includes Seneca corporate results and eliminations. Upstream
  • 35. 35 Proved Reserves & Development Costs 42.9 41.6 38.5 33.7 29.0 988 1,300 1,683 2,142 1,675 1,246 1,549 1,914 2,344 1,849 0 500 1,000 1,500 2,000 2,500 3,000 2012 2013 2014 2015 2016 At September 30 Natural Gas (Bcf) Crude Oil (MMbbl) (1)  117% Reserve Replacement Rate (adjusted for revisions and sales)  65% Proved Developed  35% Proved Undeveloped (1) Includes approximately 69 Bcf of natural gas proved reserves in Appalachia that will be transferred in fiscal 2017 as interests in the joint development wells are conveyed to the partner. (2) Reflects 246 Bcfe of natural gas reserves that were conveyed and sold to joint development partner and 16 Bcfe of Upper Devonian sales (3) FY 2016 net negative revisions include 227 Bcfe of proved reserves that were revised due to lower oil and gas pricing. Total Proved Reserves (Bcfe) Upstream Proved Reserves - FYE '15 2,344 FY '16 Production (161) Mineral Sales(2) (262) Net Negative Revisions(3) (262) Extensions & Discoveries 190 Proved Reserves - FYE '16 1,849 Fiscal 2016 Proved Reserves Reconciliation (Bcfe) Fiscal 2016 Proved Reserves Stats
  • 36. 36 Seneca Resources Net Production (Bcfe) Seneca Production 20.5 20.0 21.2 21.2 20.5 20-22 62.9 100.7 139.3 136.6 140.6 125-14883.4 120.7 160.5 157.8 161.1 145-170 0 50 100 150 200 250 2012 2013 2014 2015 2016 2017E Appalachia West Coast (California) (1) Joint Development Agreement tempers net production growth in FY17 (1) Refer to slide 39 for additional details on fiscal 2016 firm sales and local Appalachian spot market exposure.  Gross production expected to grow ~10%  Growth is largely being generated from joint development wells where Seneca has 26% NRI, resulting in flat net production YOY  Growth will in gross production will benefit NFG Midstream businesses:  Gathering segment throughput and revenues  Utilization of firm transport capacity on NFG pipelines (Northern Access) Upstream
  • 37. 37 Long-Term Contracts Supporting Appalachian Growth - 250 500 750 1,000 2017 2018 2019 2020 2021 2022 Fiscal Year Start Firm Sales(1) (1) Includes base firm sales contracts not tied to firm transportation capacity. Base firm sales are either fixed priced or priced at an index (e.g., NYMEX ) +/- a fixed basis and do not carry any transportation costs. See slide 39 for details on firm sales portfolio for fiscal 2017. (2) Includes capacity on both National Fuel Gas Supply Corp. and Empire Pipeline, Inc., both wholly owned subsidiaries of National Fuel Gas Company. Atlantic Sunrise (Transco) Delivery Markets: Mid-Atlantic & Southeast U.S. 189,405 Dth/d Northern Access 2016 (NFG(2), TransCanada & Union) Delivery Markets: Canada-Dawn & NY-TGP200 490,000 Dth/d Niagara Expansion (TGP & NFG) Delivery Markets: Canada-Dawn & TETCO 170,000 Dth/d Northeast Supply Diversification 50,000 Dth/d Gross Firm Sales and Firm Transport Volumes Under Contract (Thousands Dth per Day) Atlantic Sunrise now expected July 2018 Northern Access on track for Nov. 2017 ~500 MDth/d gross production sold on firm basis in FY17 Upstream
  • 38. 38 Firm Transportation Commitments Volume (Dth/d) Production Source Delivery Market Demand Charges ($/Dth) Gas Marketing Strategy Northeast Supply Diversification Project Tennessee Gas Pipeline Atlantic Sunrise WMB - Transco In-service: Mid-2018(1) Niagara Expansion TGP & NFG Northern Access NFG – Supply & Empire In-Service: Nov. 1 2017 50,000 189,405 158,000 350,000 EDA -Tioga County Covington & Tract 595 EDA - Lycoming County Tract 100 & Gamble WDA – Clermont/ Rich Valley WDA – Clermont /Rich Valley 12,000 140,000 Canada (Dawn) Mid-Atlantic/ Southeast Canada (Dawn) TETCO (SE Pa.) Canada (Dawn) TGP 200 (NY) $0.50 (3rd party) $0.73 (3rd party) NFG pipelines = $0.24 3rd party = $0.43 NFG pipelines = $0.12 NFG pipelines = $0.38 NFG pipelines = $0.50 3rd party = $0.21 Firm Sales Contracts 50,000 Dth/d Dawn/NYMEX+ 10 years CurrentlyIn-ServiceFutureCapacity Firm Sales Contracts 158,000 Dth/d Dawn/NYMEX+ 8 to 15 years Firm Sales Contracts 189,405 Dth/d NYMEX+ First 5 years Firm Sales Contracts 145,000 Dth/d Dawn/Fixed Price First 3 years (1) WMB is now targeting s the middle of calendar 2018 following the change in the timing of the environmental review from FERC. Upstream
  • 39. 39 Firm Sales Provide Market for Appalachian Production 105,800 Plus $0.03 93,800 Less $0.01 161,200 Less $0.17 170,500 Less $0.17 33,300 Less $0.33 29,800 Less $0.33 58,200 Less $0.01 61,600 Less $0.02 19,400 Less $0.02 21,000 Less $0.02 158,500 $2.45 160,200 $2.56 145,000 $2.45 146,400 $2.45 355,800 345,400 325,600 337,900 Q1 FY17 Q2 FY17 Q3 FY17 Q4 FY17 Fixed Price Dawn DOM SP NYMEX Gross vs. Net Firm Sales Volumes (Dth per Day) Q1 FY17 Q2 FY17 Q3 FY17 Q4 FY17 Gross 493,000/d 483,000/d 483,000/d 483,000/d NRI Owners(2) 137,200/d 137,600/d 157,400/d 145,100/d Net 355,800/d 345,400/d 325,600/d 337,900/d FY 17 Net Contracted Volumes (Dth per day) Contracted Index Price Differentials ($ per Dth)(1) (1) Values shown represent the price or differential to a reference price (netback price) at the point of sale. (2) Reflects adjustment to gross sales volumes to reflect impact of lease royalties in EDA and net revenue interests assigned to joint development partner on certain contracts in WDA. Upstream
  • 40. 40 Strong Hedge Book in Fiscal 2017 Natural Gas Swap & Fixed Physical Sales Contracts (Millions MMBtu) 35.7 42.6 27.1 16.9 6.5 22.1 8.4 7.2 7.2 56.2 32.1 12.2 120.5 83.1 46.5 27.7 - 50.0 100.0 150.0 FY 2017 FY 2018 FY 2019 FY 2020 NYMEX Dominion Dawn & MichCon Fixed Price Physical Sales Fiscal 2017 Natural Gas Production 83% hedged(1) at $3.38 per MMBtu (2) (1) Assumes midpoint of natural gas production guidance, adjusted for year-to-date actual results. (2) Fixed price physical sales exclude joint development partner’s share of fixed price contract WDA volumes as specified under the joint development agreement. Upstream
  • 41. 41 Fiscal 2017 Production and Price Certainty 145 – 170 Bcfe 116 Bcf 4 Bcf(2) 5 - 28 Bcf(3) 20-22 Bcfe Firms Sales + Hedges Firm Sales (Unhedged) Spot Exposure California Total Seneca FINANCIAL HEDGE + FIRM SALE = PRICE CERTAINTY (1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and firm transportation costs. (2) Indicates firm sales contracts with fixed index differentials but not backed by a matching NYMEX financial hedge. (3) Includes non-operated production from Western Development Area (legacy EOG JV wells) of ~5 Bcf.  116 Bcf realizing net ~$3.10/Mcf (1)  4 Bcf of Additional Basis Protection Upstream
  • 42. 42 $1.52 $0.87 $0.65 - $0.75 FY 2015 FY 2016 FY 2017E $0.59 $0.59 $0.59 $0.22 $0.14 $0.12 $0.81 $0.73 $0.71 FY 2015 FY 2016 FY 2017E Gathering & Transport LOE (non-Gathering) G&A Taxes & Other Operating Costs  Competitive, low cost structure in Appalachia and California supports strong cash margins  Gathering fee generates significant revenue stream for affiliated gathering company  DD&A decrease due to improving Marcellus F&D costs and reduction in net plant resulting from ceiling test impairments DD&A $/Mcfe $0.52 $0.52 $0.50 $0.54 $0.44 $0.50 $0.42 $0.39 $0.38 $0.22 $0.17 $0.20 $1.70 $1.52 $1.58 FY 2015 FY 2016 FY 2017E $16.17 $14.83 $17.73 FY 2015 FY 2016 FY 2017E Appalachia LOE & Gathering $/Mcfe California LOE $/Boe Seneca Resources Consolidated $/Mcfe (1) (2) (2) (1) (1) Excludes $7.9 million , or $0.05 per Mcfe, of professional fees relating to the joint development agreement announced in December 2015. (2) The total of the two LOE components represents the midpoint of the LOE guidance range of $0.95 to $1.05 per Mcfe for fiscal 2017. Upstream
  • 44. 44 NewYork & Pennsylvania Service Territories New York Total Customers(1): 528,312 ROE: 9.1% (NY PSC Rate Case Settlement, May 2014) Rate Mechanisms: o Earnings Sharing o Revenue Decoupling o Weather Normalization o Low Income Rates o Merchant Function Charge (Uncollectibles Adj.) o 90/10 Sharing (Large Customers) Filed Rate Case with NY PSC on 4/28/16 Pennsylvania Total Customers(1): 213,924 ROE: Black Box Settlement (2007) Rate Mechanisms: o Low Income Rates o Merchant Function Charge (1) As of September 30, 2016. Downstream
  • 45. 45 NewYork Rate Case Key Drivers • Requesting rate relief that would increase annual revenues by $41.7 million • Key drivers of revenue requirement:  Significant increase in net plant - $127.5 million - and related depreciation expense since 9/30/2006, the test year associated with the 2007 rate proceeding  Continued investment in pipeline replacement and system modernization to enhance and ensure safe, reliable service • Accelerated removal of vintage pipe from current annual target of 95 miles to 110 miles • Replacement of aging information technology infrastructure completed in 2nd half of FY16  Commitment to low income customer, conservation and gas expansion initiatives Timeline April 28, 2016 Request filed with NY PSC for $41.7mm in rate relief August 26, 2016 NY DPS Staff and Intervenor Testimony Filed April 27, 2017 Approximate date that revised rates may become effective (subject to “make whole” request) September 16, 2016 Rebuttal Testimony filed October 5-7, 2016 Evidentiary Hearings in Albany, NY Background On April 28, 2016, National Fuel Gas Distribution Corporation filed a request with the New York Public Service Commission (NY PSC) to amend its tariff and increase its base rates. National Fuel’s base rates have not changed since the last base rate case was litigated in 2007. October 19, 2016 Filed Notice of Impending Confidential Settlement Negotiations and request for 1 month extension of suspension period with “make whole” provision Downstream
  • 46. 46 92 94 96 98 100 102 104 106 Residential (Mcf) 20 25 30 35 40 Industrial (MMcf) Utility: Shifting Trends in Customer Usage (1) Weighted Average of New York and Pennsylvania service territories (assumes normal weather). Usage Per Account (1) 12-Months Ended September 30 Downstream
  • 47. 47 Utility: Strong Commitment to Safety $43.8 $48.1 $49.8 $54.4 $61.8$58.3 $72.0 $88.8 $94.4 $98.0 $90 - $100 $0.0 $30.0 $60.0 $90.0 $120.0 $150.0 2012 2013 2014 2015 2016 2017E Fiscal Year Capital Expenditures for Safety Total Capital Expenditures Recent increase due to ~$60MM upgrade of the Utility’s Customer Information System and anticipated acceleration of pipeline replacement program The Utility remains focused on maintaining the ongoing safety and reliability of its system Capital Expenditures ($ millions) Downstream
  • 48. 48 A Proven History of Controlling Costs $152 $152 $151 $163 $160 $16 $20 $33 $28 $23$9 $6 $10 $9 $7$177 $178 $193 $200 $189 $0 $50 $100 $150 $200 $250 2012 2013 2014 2015 2016 Fiscal Year All Other O&M Expenses O&M Pension Expense O&M Uncollectible Expense Capital Expenditures ($ millions) Downstream
  • 50. 50 Seneca Resources $63 $105 $83 $57 $38 $35-$45 $631 $428 $520 $500 $61 $145-$175 $694 $533 $603 $557 $99 $180-$220 $0 $200 $400 $600 $800 2012 2013 2014 2015 2016E 2017E Fiscal Year Appalachia West Coast (California) (2) (1) (1) FY2016 and FY 2017 capital expenditure guidance reflects the netting of up-front and recurring proceeds received from joint development partner for working interest in joint development wells. (2) Seneca’s West Coast division includes Seneca corporate and eliminations. Capital Expenditures by Division ($ millions) Appendix
  • 51. 51 Marcellus Operated Well Results EDA Development Wells: Area Producing Well Count Average IP Rate (MMcfd) Average 30-Day (MMcf/d) Average Treatable Lateral Length (ft) Covington Tioga County 47 5.2 4.1 4,023’ Tract 595 Tioga County 44(2) 7.4 4.9 4,754’ Tract 100 Lycoming County 60(2) 17.0 12.6 5,221’ Area Producing Well Count Average IP Rate (MMcfd) Average 30-Day (MMcf/d) Average Treatable Lateral Length (ft) Clermont/Rich Valley (CRV) & Hemlock Elk, Cameron & McKean counties 107(1) 6.9 5.2 (2) 7,072’ WDA Development Wells: (1) Excludes 2 wells now operated by Seneca that were drilled by another operator as part of a joint-venture. Excludes 1 well producing from the Utica shale. (2) 30-day average excludes 7 wells that have not been on line 30 days. (3) Excludes 1 well each drilled into and producing from the Geneseo Shale in Tract 595 and Tract 100. Appendix
  • 52. 52 Marcellus Shale Program Economics (1) Internal Rate of Return (IRR) is pre-tax and includes estimated well costs under current cost structure, LOE, and Gathering tariffs anticipated for each prospect. (2) Net realized price reflects either (a) price received at the well-head or (b) price received at delivery market net of firm transportation charges. ~1,150 Locations Economic Below $2.00/MMBtu $3.00 IRR % (1) $2.75 IRR % (1) $2.50 IRR % (1) DCNR 100 Dry Gas (1033 BTU) 12 5,400 13-14 74% 53% 35% $1.48 Gamble Dry Gas (1033 BTU) 43 4,600 11-12 57% 42% 25% $1.59 CRV Dry Gas (1045 BTU) 53 8,000 8.5-9.5 27% 19% 13% $1.82 Hemlock / Ridgway Dry Gas (1045 BTU) 631 8,800 8-9 29% 21% 13% $1.79 Remaining Tier 1 Dry Gas (1045 BTU) 406 8,500 7-8 25% 17% 10% $1.91 Anticipated Delivery Market Niagara Expansion Northern Access Canada (Dawn) / TGP200 Atlantic Sunrise Southeast US (NYMEX+) Net Realized Price (2) Required for 15% IRR WDAEDA NYMEX / DAWN Pricing Prospect Product Locations Remaining to Be Drilled Completed Lateral Length (ft) Average EUR (Bcf) Appendix
  • 53. 53 Hedge Positions Natural Gas Volumes in thousand MMBtu; Prices in $/MMBtu Volume Avg. Price Volume Avg. Price Volume Avg. Price Volume Avg. Price Volume Avg. Price NYMEX Swaps 35,710 $4.29 42,570 $3.34 27,060 $3.17 16,880 $3.07 4,840 $3.01 Dominion Swaps 6,540 $3.86 - - - - - - - - MichCon Swaps 3,000 $4.10 - - - - - - - - Dawn Swaps 19,100 $3.70 8,400 $3.08 7,200 $3.00 7,200 $3.00 600 $3.00 Fixed Price Physical 56,150 $2.60 29,366 $2.46 11,947 $3.09 3,567 $3.24 - - Total 120,500 $3.38 80,336 $2.99 46,207 $3.13 27,647 $3.07 5,440 $3.01 Crude Oil Volumes & Prices in Bbl Avg. Avg. Avg. Price Price Price Brent Swaps 123,000 $92.27 24,000 $91.00 - - NYMEX Swaps 1,185,000 $61.34 663,000 $55.19 300,000 $53.00 Total 1,308,000 $64.25 687,000 $56.44 300,000 $53.00 Fiscal 2021 Vol. Vol. Fiscal 2019 Fiscal 2020Fiscal 2017 Fiscal 2018 Fiscal 2017 Fiscal 2018 Fiscal 2019 Vol. (1) (1) Fixed price physical sales exclude joint development partner’s share of fixed price contract WDA volumes as specified under the joint development agreement. Appendix
  • 54. 54 Comparable GAAP Financial Measure Slides & Reconciliations This presentation contains certain non-GAAP financial measures. For pages that contain non-GAAP financial measures, pages containing the most directly comparable GAAP financial measures and reconciliations are provided in the slides that follow. The Company believes that its non-GAAP financial measures are useful to investors because they provide an alternative method for assessing the Company’s ongoing operating results and for comparing the Company’s financial performance to other companies. The Company’s management uses these non-GAAP financial measures for the same purpose, and for planning and forecasting purposes. The presentation of non-GAAP financial measures is not meant to be a substitute for financial measures prepared in accordance with GAAP. The Company defines Adjusted EBITDA as reported GAAP earnings before the following items: interest expense, depreciation, depletion and amortization, interest and other income, impairments, items impacting comparability and income taxes. Appendix
  • 55. 55 Non-GAAP Reconciliations – Adjusted EBITDA Appendix Reconciliation of Adjusted EBITDAto Consolidated Net Income ($ Thousands) FY 2012 Total Adjusted EBITDA Exploration & Production Adjusted EBITDA 397,129$ 492,383$ 539,472$ 422,289$ 363,830$ Pipeline & Storage Adjusted EBITDA 136,914 161,226 186,022 188,042 199,446 Gathering Adjusted EBITDA 14,814 29,777 64,060 68,881 78,685 Utility Adjusted EBITDA 159,986 171,669 164,643 164,037 148,683 Energy Marketing Adjusted EBITDA 5,945 6,963 10,335 12,237 6,655 Corporate & All Other Adjusted EBITDA (10,674) (9,920) (11,078) (11,900) (8,238) Total Adjusted EBITDA 704,114$ 852,098$ 953,454$ 843,586$ 789,061$ Total Adjusted EBITDA 704,114$ 852,098$ 953,454$ 843,586$ 789,061$ Minus: Interest Expense (86,240) (94,111) (94,277) (99,471) (121,044) Plus: Interest and Other Income 8,822 9,032 13,631 11,961 14,055 Minus: Income Tax Expense (150,554) (172,758) (189,614) 319,136 232,549 Minus: Depreciation, Depletion & Amortization (271,530) (326,760) (383,781) (336,158) (249,417) Minus: Impairment of Oil and Gas Properties (E&P) - - - (1,126,257) (948,307) Plus: Reversal of Stock-Based Compensation - - - 7,776 - Plus: Elimination of Other Post-Retirement Regulatory Liability (P&S) 21,672 - - - - Minus: Pennsylvania Impact Fee Related to Prior Fiscal Years (E&P) (6,206) - - - - Minus: New York Regulatory Adjustment (Utility) - (7,500) - - - Minus: Joint Development Agreement Professional Fees - - - - (7,855) Rounding (1) - - - Consolidated Net Income 220,077$ 260,001$ 299,413$ (379,427)$ (290,958)$ Consolidated Debt to Total Adjusted EBITDA Long-Term Debt, Net of Current Portion (End of Period) 1,149,000$ 1,649,000$ 1,649,000$ 2,099,000$ 2,099,000$ Current Portion of Long-Term Debt (End of Period) 250,000 - - - - Notes Payable to Banks and Commercial Paper (End of Period) 171,000 - 85,600 - - Total Debt (End of Period) 1,570,000$ 1,649,000$ 1,734,600$ 2,099,000$ 2,099,000$ Long-Term Debt, Net of Current Portion (Start of Period) 899,000 1,149,000 1,649,000 1,649,000 2,099,000 Current Portion of Long-Term Debt (Start of Period) 150,000 250,000 - - - Notes Payable to Banks and Commercial Paper (Start of Period) 40,000 171,000 - 85,600 - Total Debt (Start of Period) 1,089,000$ 1,570,000$ 1,649,000$ 1,734,600$ 2,099,000$ Average Total Debt 1,329,500$ 1,609,500$ 1,691,800$ 1,916,800$ 2,099,000$ Average Total Debt to Total Adjusted EBITDA 1.89 x 1.89 x 1.77 x 2.27 x 2.66 x FY 2013 FY 2014 FY 2015 FY 2016
  • 56. 56 Non-GAAP Reconciliations – Capital Expenditures Appendix Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures ($ Thousands) FY 2017 FY 2012 FY 2013 FY 2014 FY 2015 FY 2016 Forecast Capital Expenditures from Continuing Operations Exploration & Production Capital Expenditures 693,810$ 533,129$ 602,705$ 557,313$ 256,104$ $180,000 - $220,000 Pipeline & Storage Capital Expenditures 144,167 56,144$ 139,821$ 230,192$ 114,250$ $390,000 - $440,000 Gathering Segment Capital Expenditures 80,012 54,792$ 137,799$ 118,166$ 54,293$ $65,000 - $75,000 Utility Capital Expenditures 58,284 71,970$ 88,810$ 94,371$ 98,007$ $90,000 - $100,000 Energy Marketing, Corporate & All Other Capital Expenditures 1,121 1,062$ 772$ 467$ 397$ Total Capital Expenditures from Continuing Operations 977,394$ 717,097$ 969,907$ 1,000,509$ 523,051$ $725,000 - $835,000 Plus (Minus) Accrued Capital Expenditures Exploration & Production FY 2016 Accrued Capital Expenditures -$ -$ -$ -$ (25,215)$ Exploration & Production FY 2015 Accrued Capital Expenditures - - - (46,173) 46,173 Exploration & Production FY 2014 Accrued Capital Expenditures - - (80,108) 80,108 - Exploration & Production FY 2013 Accrued Capital Expenditures - (58,478) 58,478 - - Exploration & Production FY 2012 Accrued Capital Expenditures (38,861) 38,861 - - - Exploration & Production FY 2011 Accrued Capital Expenditures 103,287 - - - - Pipeline & Storage FY 2016 Accrued Capital Expenditures - - - - (18,661) Pipeline & Storage FY 2015 Accrued Capital Expenditures - - - (33,925) 33,925 Pipeline & Storage FY 2014 Accrued Capital Expenditures - - (28,122) 28,122 - Pipeline & Storage FY 2013 Accrued Capital Expenditures - (5,633) 5,633 - - Pipeline & Storage FY 2012 Accrued Capital Expenditures (12,699) 12,699 - - - Pipeline & Storage FY 2011 Accrued Capital Expenditures 16,431 - - - - Gathering FY 2016 Accrued Capital Expenditures - - - - (5,355) Gathering FY 2015 Accrued Capital Expenditures - - - (22,416) 22,416 Gathering FY 2014 Accrued Capital Expenditures - - (20,084) 20,084 - Gathering FY 2013 Accrued Capital Expenditures - (6,700) 6,700 - - Gathering FY 2012 Accrued Capital Expenditures (12,690) 12,690 - - - Gathering FY 2011 Accrued Capital Expenditures 3,079 - - - - Utility FY 2016 Accrued Capital Expenditures - - - - (11,203) Utility FY 2015 Accrued Capital Expenditures - - - (16,445) 16,445 Utility FY 2014 Accrued Capital Expenditures - - (8,315) 8,315 - Utility FY 2013 Accrued Capital Expenditures - (10,328) 10,328 - - Utility FY 2012 Accrued Capital Expenditures (3,253) 3,253 - - - Utility FY 2011 Accrued Capital Expenditures 2,319 - - - - Total Accrued Capital Expenditures 57,613$ (13,636)$ (55,490)$ 17,670$ 58,525$ Total Capital Expenditures per Statement of Cash Flows 1,035,007$ 703,461$ 914,417$ 1,018,179$ 581,576$ $725,000 - $835,000
  • 57. 57 Non-GAAP Reconciliations – E&P Adjusted EBITDA Reconciliation of Exploration & Production Adjusted EBITDAfor Appalachia and West Coast divisions to Exploration & Production Segment Net Income ($ Thousands) Appalachia West Coast Total E&P Appalachia West Coast Total E&P Reported GAAP Earnings 3,801$ 12,943$ 16,744$ (425,691)$ (27,151)$ (452,842)$ Depreciation, Depletion and Amortization 22,039 5,338 27,377 114,843 25,120 139,963 Interest and Other Income (78) - (78) (180) (678) (858) Interest Expense 12,920 632 13,552 53,066 2,368 55,434 Income Taxes 2,758 2,048 4,806 (307,737) (26,292) (334,029) Impairment of Oil and Gas Producing Properties 27,985 4,771 32,756 821,616 126,691 948,307 Joint Development Agreement Professional Fees - - - 7,855 - 7,855 Adjusted EBITDA 69,425$ 25,732$ 95,157$ 263,772$ 100,058$ 363,830$ Appalachia West Coast Total E&P Appalachia West Coast Total E&P Production: Gas Production (MMcf) 34,711 779 35,490 140,457 3,090 143,547 Oil Production (MBbl) 12 712 724 28 2,895 2,923 Total Production (Mmcfe) 34,783 5,051 39,834 140,625 20,460 161,085 Adjusted EBITDAMargin per Mcfe 2.00$ 5.09$ 2.39$ 1.88$ 4.89$ 2.26$ Total Production (Mboe) NM 842 NM NM 3,410 NM Adjusted EBITDAMargin per Boe NM 30.56$ NM NM 29.34$ NM Note: Seneca West Coast division includes Seneca corporate and eliminations. Three Months Ended September 30, 2016 Twelve Months Ended Setpember 30, 2016 Appendix
  • 58. 58 Non-GAAP Reconciliations – E&P Operating Expenses Appendix Reconciliation of Exploration & Production Segment Operating Expenses by Division ($000s unless noted otherwise) Appalachia West Coast(2) Total E&P Appalachia West Coast(2) Total E&P Appalachia West Coast(2) Total E&P Appalachia West Coast(2) Total E&P $/ Mcfe $ / Boe $ / Mcfe $/ Mcfe $ / Boe $ / Mcfe Operating Expenses: Gathering & Transportation Expense (1) $82,949 $309 $83,258 $0.59 $0.09 $0.52 $81,212 $435 $81,647 $0.59 $0.12 $0.52 Lease Operating Expense $20,402 $50,254 $70,656 $0.14 $14.74 $0.44 $29,510 $56,643 $86,153 $0.22 $16.04 $0.54 Lease Operating and Transportation Expense $103,351 $50,563 $153,914 $0.73 $14.83 $0.96 $110,722 $57,078 $167,800 $0.81 $16.17 $1.06 General & Administrative Expense $55,293 $15,305 $70,598 $0.39 $4.49 $0.44 $47,445 $18,669 $66,114 $0.35 $5.29 $0.42 All Other Operating and Maintenance Expense $6,228 $6,604 $12,832 $0.04 $1.94 $0.08 $5,296 $9,008 $14,304 $0.04 $2.55 $0.09 Property, Franchise and Other Taxes $5,403 $8,391 $13,794 $0.04 $2.46 $0.09 $9,046 $11,121 $20,167 $0.07 $3.15 $0.13 Total Taxes & Other $11,631 $14,995 $26,626 $0.08 $4.40 $0.17 $14,342 $20,129 $34,471 $0.11 $5.70 $0.22 Depreciation, Depletaion & Amortization $139,963 $0.87 $239,818 $1.52 Production: Gas Production (MMcf) 140,457 3,090 143,547 136,404 3,159 139,563 Oil Production (MBbl) 28 2,895 2,923 30 3,004 3,034 Total Production (Mmcfe) 140,625 20,460 161,085 136,584 21,183 157,767 Total Production (Mboe) 23,438 3,410 26,848 22,764 3,531 26,295 (1) Gathering and Transportation expense is net of any payments received from JDA partner for the partner's share of gathering cost (2) Seneca West Coast division includes Seneca corporate and eliminations. Twelve Months Ended September 30, 2016 Twelve Months Ended September 30, 2015